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Home My WebLink About2021-03-03 Utilities Advisory Commission Agenda PacketMATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE COMMISSION AFTER DISTRIBUTION OF THE AGENDA PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE UTILITIES DEPARTMENT AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS HOURS. AMERICANS WITH DISABILITY ACT (ADA) Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance. NOTICE IS POSTED IN ACCORDANCE WITH GOVERNMENT CODE SECTION 54954.2(a) OR 54956 Supporting materials are available online at https://www.cityofpaloalto.org/gov/boards/uac/default.asp on Thursday, 5 days preceding the meeting. ****BY VIRTUAL TELECONFERENCE ONLY**** Join Zoom Webinar Here Meeting ID: 966 9129 7246 Phone: 1 (669) 900-6833 Pursuant to the provisions of California Governor’s Executive Order N-29-20, issued on March 17, 2020, to prevent the spread of COVID-19, this meeting will be held by virtual teleconference only, with no physical location. The meeting will be broadcast on Cable TV Channel 26, live on Midpen Media Center at https://midpenmedia.org. Members of the public who wish to participate by computer or phone can find the instructions at the end of this agenda. I. ROLL CALL II. AGENDA REVIEW AND REVISIONS III. 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. IV. APPROVAL OF THE MINUTES Approval of the Minutes of the Utilities Advisory Commission Meeting held on February 3, 2021 V. UNFINISHED BUSINESS - None VI. UTILITIES DIRECTOR REPORT VII. NEW BUSINESS 1. Staff Recommendation That the Utilities Advisory Commission Recommend the City Action Council Approve 10 Year Energy Efficiency Goals for 2022-2031 2. Staff Recommendation That the Utilities Advisory Commission Recommend the City Action Council Adopt a Resolution Approving the Fiscal Year 2022 Gas Utility Financial Plan, Including Proposed Transfers and an Amendment to the Gas Utility Reserve Management Practices, and Increasing Gas Rates by Amending Rate Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas Service) UTILITIES ADVISORY COMMISSION – SPECIAL MEETING WEDNESDAY, MARCH 3, 2021 – 4:00 P.M. ZOOM Webinar Chairman: Lisa Forssell  Vice Chair: Lauren Segal  Commissioners: Michael Danaher, Donald Jackson, A.C. Johnston, Greg Scharff, and Loren Smith  Council Liaison: Eric Filseth MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE COMMISSION AFTER DISTRIBUTION OF THE AGENDA PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE UTILITIES DEPARTMENT AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS HOURS. AMERICANS WITH DISABILITY ACT (ADA) Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance. 3. Staff Recommendation That the Utilities Advisory Commission Recommend the City Action Council Adopt a Resolution Approving the Fiscal Year 2022 Electric Financial Plan and Reserve Transfers, and Amending Utility Rate Schedules E-EEC-1 (Export Electricity Compensation), E-NSE-1 (Net Surplus Electricity Compensation), E-2-G (Residential Master- Metered and Small Non- Residential Green Power Electric Service), E-4-G (Medium Non Residential Green Power Electric Service), and E-7-G (Large Non-Residential Electric Service) 4. Staff Recommendation That the Utilities Advisory Commission Recommend the City Action Council Adopt a Resolution Approving the Fiscal Year 2022 Water Utility Financial Plan, With no Water Rate Increase for Fiscal Year 2022 VIII. COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS IX. FUTURE TOPICS FOR UPCOMING MEETINGS: April 07, 2021 SUPPLEMENTAL INFORMATION - The materials below are provided for informational purposes, not for action or discussion during UAC Meetings (Govt. Code Section 54954.2(a)(3)). Informational Reports 12-Month Rolling Calendar Public Letter(s) to the UAC • Informational Update on REC Exchange Program for 2020 and 2021 in Accordance With the City's Amended Electric Supply Portfolio Carbon Neutral Plan MATERIALS RELATED TO AN ITEM ON THIS AGENDA SUBMITTED TO THE COMMISSION AFTER DISTRIBUTION OF THE AGENDA PACKET ARE AVAILABLE FOR PUBLIC INSPECTION IN THE UTILITIES DEPARTMENT AT PALO ALTO CITY HALL, 250 HAMILTON AVE. DURING NORMAL BUSINESS HOURS. AMERICANS WITH DISABILITY ACT (ADA) Persons with disabilities who require auxiliary aids or services in using City facilities, services or programs or who would like information on the City’s compliance with the Americans with Disabilities Act (ADA) of 1990, may contact (650) 329-2550 (Voice) 24 hours in advance. PUBLIC COMMENT INSTRUCTIONS Members of the Public may provide public comments to teleconference meetings via email, teleconference, or by phone. 1. Written public comments may be submitted by email to UACPublicMeetings@CityofPaloAlto.org. 2. Spoken public comments using a computer will be accepted through the teleconference meeting. To address the Commission, click on the link below for the appropriate meeting to access a Zoom- based meeting. Please read the following instructions carefully. A. You may download the Zoom client or connect to the meeting in-browser. If using your browser, make sure you are using a current, up-to-date browser: Chrome 30+, Firefox 27+, Microsoft Edge 12+, Safari 7+. Certain functionality may be disabled in older browsers including Internet Explorer. B. You will be asked to enter an email address and name. We request that you identify yourself by name as this will be visible online and will be used to notify you that it is your turn to speak. C. When you wish to speak on an agenda item, click on “raise hand.” The Attendant will activate and unmute speakers in turn. Speakers will be notified shortly before they are called to speak. D. When called, please limit your remarks to the time limit allotted. E. A timer will be shown on the computer to help keep track of your comments. 3. Spoken public comments using a smart phone use the telephone number listed below. When you wish to speak on an agenda item hit *9 on your phone so we know that you wish to speak. You will be asked to provide your first and last name before addressing the Council. You will be advised how long you have to speak. When called please limit your remarks to the agenda item and time limit allotted. Join Zoom Webinar Here Meeting ID: 966-9129-7246 Phone number: 1 669 900 6833 Utilities Advisory Commission Minutes Approved on: Page 1 of 8 UTILITIES ADVISORY COMMISSION MEETING MINUTES OF FEBRUARY 3, 2021 REGULAR MEETING CALL TO ORDER Chair Forssell called the meeting of the Utilities Advisory Commission (UAC) to order at 4:00 p.m. Present: Chair Forssell, Vice Chair Segal, Commissioners Danaher, Jackson, Johnston, Scharff and Smith Absent: AGENDA REVIEW AND REVISIONS None. ORAL COMMUNICATIONS None. APPROVAL OF THE MINUTES Commissioner Danaher moved to approve the minutes of the January 6, 2021 meeting with the revisions of the date. Commissioner Johnston seconded the motion. The motion carried 7-0 with Chair Forssell, Vice Chair Segal, and Commissioners Danaher, Jackson, Johnston, Scharff, and Smith voting yes. UNFINISHED BUSINESS None. UTILITIES DIRECTOR REPORT Dean Batchelor, Utilities Director, delivered the Director's Report. Utilities Sales and Delinquencies Water and electric utility sales continue to be at or above forecasts for FY 2021. Electricity consumption continues to be 5% to 10% below previous years, as forecasted, while water use continues to be at or above previous years, which is higher than forecasted. Gas consumption was low in summer and fall, below forecasts, but as winter started gas consumption rose significantly and consumption is now roughly the same as in previous winters. Bill delinquencies continue to rise. As of the end of December, delinquencies for all utilities totaled roughly $1.2 million. While delinquencies continue to rise gradually, they are still well within the amounts estimated in our financial forecasts. And many customers with delinquent accounts will eventually pay their delinquent balances off, based on prior experience. Status Update on the Water Year To-Date While it is still early in the water year, precipitation is currently at only about 40% of normal for the year in the Northern Sierras, the primary watershed for the hydroelectric generation we receive from the Central Valley Project, and 30% of normal in the Central Sierras, where the Calaveras hydroelectric project is located as well as the water sources for the SFPUC. A bad water year can result in as much as $8 million to $10 million DRAFT Utilities Advisory Commission Minutes Approved on: Page 2 of 8 in additional costs for the electric utility. The electric utility has hydro stabilization reserves of $11.7 million currently, which is lower than the target level of $17 million, but well above the $3 million minimum. This is an issue we will be tracking through the spring and we may need to come back to the UAC and Council to discuss options for the electric utility if the water year does not improve. The City’s water supply, on the other hand, is in a better position. The SFPUC may consider voluntary restrictions on water use if the water year does not improve, but is not signaling a need for mandatory restrictions at this item. Clean Fuel Rewards Program: Under the statewide program all Palo Alto residents purchasing new electric vehicles are eligible for a Clean Fuel Rewards point-of-sale $1,500 rebate at participating dealerships. Since its launch in November 2020, the program has received ~15,000 rebate applications and roughly 5,000 rebates have been paid as of Dec 31, 2020. The number of applicants from Palo Alto is not known at this time. The total new EV sales in California is projected to be 250,000 in CY 2021, with Palo Alto anticipating about 1,500 additional EV registrations. CALeVIP: The California Energy Commission’s California Electric Vehicle Infrastructure Project (CALeVIP) launched in Santa Clara and San Mateo counties on Dec 16, 2020. This project provides rebates for Level 2 and Level 3 EV charger installation. CPAU has committed $1 million of Low Carbon Fuel Standard (LCFS) funds to receive $1 million in matching grant funding. In addition to rebate applications from the community the City’s public works department for five DC fast charger rebates for installation in public garages and has been provisionally approved for $350,000 in rebates. Home Efficiency Genie Virtual Audit: The Home Efficiency Genie is now offering virtual home energy and water efficiency assessments using a smart phone-based interactive platform for $49. This adapted version of the advisor visit allows the Genie technician to engage with residents in a live review of their home. After the assessment, the technician sends a report outlining the findings, discussion points and possible next steps. Residents are offered a safe delivery of energy and water saving devices like a smart power strip, LED light bulbs, high efficiency shower heads and faucet aerators. Since the launch of the virtual program in November, seven virtual assessments have been performed with positive feedback. Recent Offset Purchases: Following Council’s approval of the updated Carbon Neutral Gas Plan in December 2020, staff solicited proposals for carbon offsets from five brokers with whom the City has agreements in place. Staff received three proposals, and on January 7th, the City purchased 120,000 metric tons (MT) of carbon offsets from four projects at an average price of $5.81/MT CO2, well below the Council-approved maximum price of $19/MT. The offsets purchased and retired were from 53% coal mine methane capture, 43% forestry, and 4% livestock project types and adhered to all criteria outlined in the Carbon Neutral Gas Plan. These offset purchases make the city’s gas sales carbon neutral through December 2020. Rosamond Solar virtual ribbon cutting: Please join us at a virtual ribbon cutting ceremony for the Rosamond Central Solar Project on February 3 at 10 am. The Rosamond project will provide CPAU with 26 MW of solar electricity beginning in 2023. Rosamond is the sixth large-scale solar project to come online to supply Palo Alto with renewable energy. Solar energy will now supply 44-45%, close to half, of Palo Alto’s total electric needs each year. We will share the link to the ribbon cutting event with the UAC via email. Commissioner Danaher reported that he had no objections to postponing the discussion regarding home electrification permits. In reply to Commissioner Jackson’s inquires of if the 2nd transmission line will be above or below the ground and sea level rise impacts, Director Bachelor explained that the existing line is on towers and the new line will also be on towers. The towers are roughly 70 to 80 feet in the air which mitigates any sea level rise impacts. Utilities Advisory Commission Minutes Approved on: Page 3 of 8 NEW BUSINESS ITEM 1: ACTION: Staff Recommendation That the Utilities Advisory Commission Recommend the City Council Adopt a Resolution Approving the FY 2022 Wastewater Collection Utility Financial Plan Including Transfers to and From Wastewater Collection Utility Reserve Accounts and an Amendment to the Wastewater Collection Utility Reserves Management Practices; and Adopt a Resolution Adjusting 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). Dean Bachelor, Utilities Director, introduced Lisa Bilir who presented the item to the UAC. Lisa Bilir, Resource Planner, confirmed that the discussion is focused on the Wastewater Collection Utility Financial Plan. In 2020 City Council did not increase the wastewater rates and the current rates had been in place since July 1, 2019. Staff recommended a 3 percent overall revenue increase, an additional 3 percent increase in FY 2023, and a 5 percent increase annually starting in FY 2024 through FY 2026. Staff provided an alternate proposal of a zero percent increase but if adopted, the Wastewater Utility Fund would need to reduce spending or differ capital spending on the Collection System of approximately $200,000 per year during the 5 years. The key drivers for a 3 percent increase were due to a series of large increases in the treatment costs during the 5-year planning period as well as addressing the on-going needs of the Capital Improvement Projects (CIP) in the Collection System. To keep the increased percentage to 3 percent, staff had reduced the size and cost of each sewer replacement in the Collection System as well as differed two sewer replacements by one year. A Cost of Service Analysis was completed and the results of the study were incorporated into the rate proposals. Staff also proposed changes to the CIP Reserve to reflect the CIP spending on the Collection System as well as the revenue that is used in the CIP Reserve. With a zero percent increase and no further cost cuts, the Wastewater Operations Reserve yearend balance would drop close to the reserve minimum in the projected 10-year forecast. With a 3 percent increase, residential customers would see their bill increased by $1.95 per month, commercial customers would see an increase of $.12 per Centum Cubic-feet (CCF), and restaurant customers would see a reduced of $.26 per CCF. One highlighted of the Cost of Service Analysis was the importance of flow volume and flow volume is the volume of wastewater discharge from each customer class as well as from the City as a whole. Over the last 10 to 12-years, wastewater flows have declined across all customer classes, but the non-residential flow volumes have decreased more than residential flow volumes. That change reflected why there is a larger increase for residential customers than commercial customers. The City continued to have lower residential rates than surrounding Cities by 29 percent and the City will maintain that status through the projected 5-years. Commercial continued to be higher than surrounding Cities by 10 percent and restaurant bills were lower than surrounding Cities by 6 percent. Staff requested support from the UAC for the annual $4.35 million of funding to the CIP Reserve, a transfer of $2.2 million from the Operations Reserve to the CIP Reserve in FY 2022, and the associated changes to the reserve guidelines. In response to Commissioner Johnston’s questions regarding decreasing the size of several of the sewer projects and postponement of projects, Silvia Santos, WGW Engineering Manager, answered that it meant that the amount of sewer footage that is being replaced has been reduced. Bilir confirmed that several projects were postponed to a subsequent year. In reply to Commissioner Johnston’s inquiries regarding if residential meant single-family only and if it mattered if a multi-family building had a common water line, Bilir noted that single-family and multi-family are on the residential rate schedule. Jonathan Abendschein, Assistant Director of Utilities Resource Management, explained that multi-family buildings that contain central water using facilities may be charged a commercial rate for water but individual residents receive individual flat rate charges for their wastewater. In answer to Commissioner Johnston’s ask of how many years the new Cost of Service Study applies to, Bilir disclosed that there is not a set amount of time and staff will reevaluate the rate burden balance between the three classes if there are changes in the data. Commissioner Johnston announced that he is concerned that residential customers have a higher burden in terms of rate increases for wastewater. He supported the contribution of a leveled amount to the CIP Reserve on an annual basis. Utilities Advisory Commission Minutes Approved on: Page 4 of 8 In answer to Vice Chair Segal’s inquiry of if the Cost of Service Study was drafted traditionally in terms of evaluating flow versus strength versus customer service costs, Bilir confirmed that the new study was drafted in a way that is similar to the existing study. She agreed that as flow decreases, concentration increases and the assumption in the study is that the strength difference across the customer classes remained the same as in the previous study. Abendschein added that there is both capacity and strength related costs in transporting and treating wastewater. James Allen, Manager Water Quality Control Plant, clarified that 34 percent of the cost if for the flow and 66 percent is for strength. If the wastewater is more concentrated then there is a cost reduction and all partners see that reduction. In response to Vice Chair Segal’s query on why residential customers are carrying a bigger portion of the overall cost if the strength of the wastewater coming from restaurants is increasing because the flow is decreasing, Bilir noted that on the Collection System cost side, more of the cost went to flow. Also, residential customers make up 94 percent of the number of customers and because restaurants are a small customer class, very small changes in the flow make a big difference in the proposed rate. Vice Chair Segal disclosed that the changes in the reserves made sense, is in alignment with the other utilities, and she supported it. In reply to her question of if the budget included sea level rise impacts to treatment plant facilities, Allen disclosed that there is a $12 million project that once completed will carry more water from the plant and that will address sea level rise up to 3-feet. Also, as facilities are constructed, the elevation of those facilities is being raised to accommodate for sea- level rise. Karin North, Assistant Director of Public Works, specified that in parallel to the work being done at the plant, a Sea Level Rise Vulnerability Assessment is underway and staff is working with the Army Core of Engineers on levy improvement projects. Commissioner Scharff stated that the City of Menlo Park, Redwood City, and the City of Hayward skewed the comparison of monthly residential bills and gave a false impression for Palo Alto’s bill. He encouraged staff to revisit the residential monthly bill comparison. He did not support the notion of having residential customers paying more for the wastewater than commercial customers. In answer to his queries of what the driving costs are for wastewater and why flow is what determines the Cost of Service Study, Bilir mentioned that the Cities used in the comparison are the Cities that are used in all of the utility comparisons. In terms of cost, 50 percent of costs go-to the treatment of wastewater, 34 percent goes to flow and on the Collection side, 97 percent of costs go to flow. In response to Commissioner Scharff’s query about why is the Cost of Service Study using flow if it is a fixed cost, Santos explained that the issue is the conditions of the pipes and the cost reflects the replacement of pipes. Abendschein added that in the short term, costs do not change based on flow, but the fixed costs are based around the peak amount of flow that is associated with the system. Costs for the system are allocated based on how much each of the different customer classes use the capacity and does not reflect short term fluctuation. The goal of the Cost of Service Study is to make sure that the only allocations that take place are ones that as necessary based on data. In answer to Commissioner Scharff’s question of how does staff determine how much pipe is needed to be replaced, Santos noted that a condition assessment is conducted on the pipelines to prioritize replacements. The City has been replacing the pipeline on average 1 mile to 2 miles every other year. Batchelor added that the 3 percent increase helps pay for past replacement projects and treatment plant projects. Staff predicted that treatment costs will continue to rise. Commissioner Smith mentioned that the City of Los Altos was not a good City to compare to for both residential and commercial bills. In answer to his question regarding if the City of Los Altos’s wastewater infrastructure is newer, Bilir confirmed that staff will investigate further why the City of Los Altos has a lower bill than Palo Alto. Abendschein clarified that staff does not know what other City’s infrastructure maintenance plans are and maintenance plays a large role in rate increases and decreases. In response to Commissioner Smith’s queries regarding the CIP Reserve and if a study had been conducted to see if the City could transfer only $2.2 million annually instead of the proposed $4.35 million, Bilir clarified that the $4.35 million is the average for the entire Collection System CIP Budget. The $2.2 million is a catch-up transfer from the Operations Reserve to the CIP Reserve to be able to fund the upcoming sewer replacement project. Abendschein added that to maintain the 5 percent increase in the outer years while absorbing the increased treatment costs, the utility is drawing on the CIP Reserve slightly. The intention is not to fund the CIP less, Utilities Advisory Commission Minutes Approved on: Page 5 of 8 the transfer is a management strategy of dealing with higher treatment costs in later years. Allen noted that in terms of treatment cost drivers, Palo Alto’s share of the fixed asset is 38.16 percent and that is the total project cost. In reply to Councilmember Filseth’s prediction that 100 percent of the costs are fixed and any variable costs were associated with flow and strength, Abendschein agreed that broadly the cost of running the collection system is entirely fixed. Allen shared that electricity costs were associated with strength as well as flow. In answer to Councilmember Filseth’s summary that the practice is to allocate the fixed cost to who uses how much flow, Allen shared that there is a breakdown of strength and flow costs between the different pieces of equipment. Councilmember Filseth commented that the issues raised are common among utilities regarding large fixed costs and unfairly distributed rate percentage allocations. In answer to Councilmember Filseth’s ask of why the City of Menlo Park and Redwood City have higher bills than Palo Alto, Bilir shared that they have newer treatment plant facilities than Palo Alto. Allen confirmed that Palo Alto is more efficient with its CIP projects than other peninsula Cities. Commissioner Scharff emphasized that the City of Santa Clara is an extremely well-run utility for wastewater and Palo Alto should be proud that its utility is better than Santa Clara’s. He requested that staff breakdown the reasons why surrounding City’s have the average bill cost that they have. In reply to Chair Forssell’s query about how much has the wastewater flow decreased and why water usage is down, Bilir disclosed that wastewater flow decreased by 11 percent overall since the last Cost of Service Study was drafted 10-years ago. The assumption from the prior Cost of Service Study was compared to the new data and that comparison showed a decrease in water usage. Another change that the new Cost of Service Study reflected is that all industrial customers are now listed under commercial customers. In answer to Chair Forssell’s question of why did the strength assumptions almost double between the two studies, Bilir predicted that it was because there was a slight increase in the amount of infiltration assumption, but staff will investigate it further. In answer to Chair Forssell’s inquire of why there is a recommendation to eliminate the fixed monthly charge for commercial and restaurant customers, Abendschein clarified that the recommendation is to eliminate a minimum charge, not a fixed charge. It was not normal to have a fixed monthly charge in a Wastewater Utility, but staff will return with a follow-up answer. ACTION: Commissioner Danaher moved that the Utilities Advisory Commission (UAC) recommend the Council: 1. Adopt a resolution approving: a. The Fiscal Year (FY) 2022 Wastewater Collection Financial Plan; and b. Up to a $4.35 million transfer from the Operations Reserve to the Capital Improvement Projects Reserve in FY 2022; and c. Up to a $2.2 million transfer from the Operations Reserve to the Capital Improvements Projects Reserve in FY 2021; and d. Amendments to the Wastewater Collection Utility Reserves Management Practices in Appendix C to the FY 2022 Wastewater Collection Financial Plan and separately in Attachment D. Commissioner Scharff seconded the motion. The motion carried 7-0 with Chair Forssell, Vice Chair Segal, and Commissioners Danaher, Jackson, Johnston, Scharff, and Smith voting yes. ACTION: Commissioner Danaher moved that the Utilities Advisory Commission (UAC) recommend the Council: 2. Adopt a resolution approving: a. Adjustments to Wastewater Collection Utility Rates Via the Amendment of 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 Utilities Advisory Commission Minutes Approved on: Page 6 of 8 Collection and Disposal – Industrial Discharger). Commissioner Johnston seconded the motion. The motion carried 7-0 with Chair Forssell, Vice Chair Segal, and Commissioners Danaher, Jackson, Johnston, Scharff, and Smith voting yes. The UAC recessed at 5:47 p.m. and returned at 5:55 p.m. ITEM 2: DISCUSSION: Discussion and Status Update on the 2020 Sustainability and Climate Action Plan. Bret Andersen appreciated that the plan focused on the shift from gas to electric. The report indicated that the commercial sector does have the potential to reach the goal of reducing carbon emissions by 80 percent by the year 2023 (80 by ‘30). The report also indicated that the neighborhood level electrification pattern has many challenges and seemed like long-term planning instead of short-term planning. He wanted to see a focus on a short-term plan. He concluded that if the Utilities Department can remove any barriers and implement easy to adopt programs, there will be little to no resistance from the community to move to all- electric. Jonathan Abendschein, Assistant Director of Utilities Resource Management, disclosed that the goal of the presentation is to give a brief update on the Sustainability and Climate Action Plan (S/CAP). Several City departments have worked on the plan. Modeling has been moved to in-house and staff predicted that those and the analysis will be completed in the coming weeks. As the analysis comes to a close, key points have been raised which included that there are costs to taking no action on climate change, costs and logistics of taking action are significant, and while the costs appear to be large, they are manageable. No plan is complete without a way to protect low-income residents, small businesses, and all the other lower financial sectors. The analysis has indicated that the whole community has to commit to all technically feasible avenues to achieve the 80 by ’30 goal. That meant greatly reducing vehicle miles traveled for employees and residents within the City. Businesses and multi-family non-residential facilities must commit to as much electrification as possible, but staff recognized that it will be challenging. For that reason, residents will be incentivized to electrify their homes even more and staff recognized that residents will need financial support, programs to make the conversion as easy as possible, and possible side benefits if the they electrify. The philosophy that staff used to design the S/CAP goals and key actions included, but were not limited to, educating and raising awareness, activation of early adopters and ensuring positive experiences, and rewarding neighborhood- level action. If the community is not ready for mandated pricing within the next 2 to 4-years, staff predicted it will be hard to achieve the 80 by ’30 goal. Several foundational implementation activities were identified to move electrification forward. Those included launching high participation voluntary programs, having an extensive awareness campaign, having customer-friendly permitting, preserving and enhancing electric reliability and resiliency, and developing a plan for scaling up programs to achieve emission reduction goals. In reply to Commissioner Jackson’s request of what ‘cost in line with the annual energy cost’ meant, Abendschein confirmed that the short-term impact may be doubled energy costs. Commissioner Jackson shared that residents who are retired may be part of the vulnerable groups who need more assistance when electrifying their homes. He found the report very exciting and agreed that finding ways to help early adoption is a key point. Commissioner Danaher indicated that it is important to continue monitoring what is happening at the state level and in neighboring communities. He requested there be quarterly updates on how the City is coming along with the installation of charging networks within the City. Commissioner Johnston found the presentation very exciting and encouraging. He appreciated that staff is exploring financial incentives and making the transition customer friendly. He agreed that there needs to be reliability within the electric utility to create trust with electric customers. Vice Chair Segal agreed with the comments regarding working with the state and neighboring Cities and resiliency in the Electric Utility. She wanted to see more efforts to reach citizens be made by testing different Utilities Advisory Commission Minutes Approved on: Page 7 of 8 communication channels. She agreed that more extreme weather patterns are on the horizon and ensuring that the power will stay on is key to building trust for electrification in the community. She concluded that she is concerned about relying on contractors to do foundational services for customers. Abendschein agreed that many customers are not being reached and that there is a staffing issue. Dean Batchelor, Utilities Director, confirmed that staff is working with the state on making changes to the apprenticeship program and making the ratio one linemen per one apprentice linemen instead of three to one. Commissioner Scharff found the electric vehicle (EV) information encouraging and felt that the state will help facilitate the change from gas-powered vehicles to EVs. He was concerned about the push of 100 percent electrification of single-family homes. He wanted to see more discussion and data around vulnerable populations and how the community will be impacted by supporting them. He expressed that the goal of Palo Alto doing all this is to show that a model can be implemented to help reduce emissions, but he wanted Council and staff to think about how much this program will cost the City and if the tradeoffs are worth it. He concluded he is concerned that the City is not being straightforward and transparent about discontinuing the Gas Utility. Abendschein agreed, but he explained that releasing costs has to be done sensitively and research must be included to ensure a positive outlook towards electrification. He emphasized that there are easy steps that can be taken in order to not sticker shock the community. In terms of financing for electrifying buildings, staff is exploring ways to tie the costs to the building and not to individual owners. Staff continued to explore a financial mechanism that does not affect housing values, does not affect credit scores, and does not factor in an owner’s financial position. Commissioner Smith appreciated the efforts staff is putting towards educating the public and the neighborhood-level action plan. He suggested that staff think about the Cubberley community engagement model and how that can be applied to outreach for electrification. He wanted to see the community engagement process started now. In answer to his question regarding the UAC study session that is proposed for May of 2021, Christine Luong, Sustainability Manager, reported that staff will be bringing forward the findings of the Impact Analysis. Chair Forssell appreciated the report, the discussion, and the approach that staff is taking. She agreed that Palo Alto is small and reducing its emissions is small, but she felt that the City can be an example of what a community can do. She also agreed that state mandates will be the driving force behind folks converting their vehicles to EVs, but she added that the City can help with that effort by removing barriers for EV users. She appreciated that the report disclosed co-benefits of EVs. In response to her question of is there qualified talent to fill the staffing positions that are needed to implement the plan, Abendschein predicted that filling the linemen and engineering position will be challenging. Batchelor disclosed that most likely the City will have to hire a contracting firm to analyze the existing system as well as rebuild the system along with City crews. Abendschein added that internal discussions will take place regarding staffing for voluntary programs. Chair Forssell suggested that staff explore having an all-electric model home and have it open to the public. Abendschein concurred and added that regional collaboration could make that happen. In answer to Commissioner Scharff’s query regarding why the S/CAP goals still supported vehicle hybrids, Abendschein noted that some folks have strong vehicle preferences and the S/CAP reflects that sensitivity. Luong added that plug-in hybrids are also a bridging strategy for renters. In reply to Commissioner Scharff’s inquiry of if reducing traffic is different than reducing emissions, Abendschein clarified that reducing traffic is a cheaper way to reduce emissions than electrifying vehicles. Commissioner Scharff noted that for a long time the City has pushed to reduce vehicles on roadways and yet traffic continued to stay steady or even increased. He did not believe that large numbers of folks will change their driving habits. Abendschein agreed that the City needed to be realistic about how much can be achieved. Councilmember Filseth shared that the report was exactly what Council has asked for. He confirmed that there were still several areas that needed further work such as informing folks that they need to reduce their vehicle trips. Utilities Advisory Commission Minutes Approved on: Page 8 of 8 ACTION: None COMMISSIONER COMMENTS and REPORTS from MEETINGS/EVENTS Commissioner Johnston thanked the staff for the report regarding the 2nd transmission line and he looked forward to hearing more about it in the future. Commissioner Jackson reported that he had attended the conference Northern California Power Agency (NCPA) had put on. Vice Chair Segal confirmed she had also attended the NCPA conference. Chair Forssell concurred she also attended the virtual conference as well as the virtual ribbon cutting ceremony for Rosamond Solar. Commissioner Scharff disclosed that he will continue to inform the UAC on events that NCPA puts on. Dean Batchelor, Utilities Director, shared that it is important that the NCPA see the UAC Commissioners attending their events. FUTURE TOPICS FOR UPCOMING MEETINGS: March 03, 2021 Vice Chair Segal wanted to see an update on sea level rise planning. Chair Forssell appreciated the quarterly report that was included in the Packet. NEXT SCHEDULED MEETING: March 03, 2021 Commissioner Danaher moved to adjourn. Commissioner Jackson seconded the motion. The motion carried 7-0 with Chair Forssell, Vice Chair Segal, and Commissioners Danaher, Jackson, Johnston, Scharff, and Smith voting yes. Meeting adjourned at 7:19 p.m. Respectfully Submitted Tabatha Boatwright City of Palo Alto Utilities City of Palo Alto (ID # 11789) Utilities Advisory Commission Staff Report Report Type: New Business Meeting Date: 3/3/2021 City of Palo Alto Page 1 Summary Title: Updated10 Year Energy Efficiency Goals Title: Staff Recommendation That the Utilities Advisory Commission Recommend the City Council Approve 10 Year Energy Efficiency Goals for 2022-2031 From: City Manager Lead Department: Utilities Recommendation Staff recommends that the Utilities Advisory Commission (UAC) recommend the City Council approve the proposed annual and cumulative Electric Efficiency Goals for the period 2022 to 2031 as shown in the table below. Executive Summary Palo Alto has long recognized cost-effective energy efficiency (EE) as the highest priority energy resource, given that EE typically displaces relatively expensive electricity generation, lowers energy bills for customers, and contributes to economic development and job creation. As required by state legislation, the City adopted its first set of 10-year energy efficiency goals in April 2007, and updated these goals in 2010, 2012, and 2017. EE savings that can be counted towards these goals are restricted to those sa vings directly attributable to utility programs that are funded by a mandated public benefits charge (2.85% of electric retail revenue). EE upgrades that customers undertake without participating in utility programs as well as EE savings achieved through federal and state appliance and building standards currently cannot be counted towards the City’s EE goals. The savings reported here and targeted by these goals represent a subset of the actual energy efficiency upgrades taking place in Palo Alto. Over the past decade, building and appliance efficiency standards have become increasingly stringent. As federal and state efficiency standards increase, the energy savings attributable to utility programs decline. For this current EE goals update, staff proposes annual EE savings targets of 0.62% in 2022, increasing to 0.78% in 2026 and holding stable through 2031, with a cumulative 10 -year EE savings of 4.4% of the City’s projected electric load. These targets reflect gradual recovery of savings from the City’s existing programs to their pre-economic downturn levels, plus the Staff: Christine Tam, Lena Perkins, Lisa Benatar and Micah Babbitt City of Palo Alto Page 2 launch of new programs focused on behavioral-based savings and conservation voltage reduction once Advanced Metering Infrastructure is in place. Summary Table: Annual Electric Energy Efficiency Goals (% of total City customer usage reduction) Electric (%) Electric MWh 2022 0.50% 4,300 2023 0.50% 4,500 2024 0.55% 4,900 2025 0.60% 5,300 2026 0.75% 6,600 2027 0.75% 6,600 2028 0.75% 6,500 2029 0.80% 6,900 2030 0.80% 6,900 2031 0.80% 6,900 Cumulative1 10-year EE Goal 4.40% 37,940 Background Council adopted the City’s first 10-year electric EE goals in April 2007. These goals targeted a cumulative reduction in the City’s electric usage of 3.5% by 2017. The goals met the state legislative requirements established by AB 2021 (2006) requiring publicly owned electric utilities to adopt annual electric efficiency savings goals over a 10-year period, with the first set of goals due by June 1, 2007 and every three years thereafter. These EE goals were used for the City of Palo Alto Utilities’ (CPAU’s) resource planning as well as for EE program budget planning. In May 2010 City Council updated the 10-year EE goals to reduce cumulative electric load by 7.2% between 2011 and 2020. The most recent set of 10-year EE goals was adopted by City Council in March 2017, with cumulative 10-year electric savings of 5.7% between 2018 and 2027. AB 2227 (2012) changed the triennial energy efficiency target-setting schedule to a quadrennial schedule, beginning March 15, 2013 and every fourth year thereafter. The next EE goals update is due to be submitted to the California Energy Commission by March 15, 2021. 1 Cumulative EE savings are not equal to the sum of the annual incremental goals due to the differences in how long the electricity savings persist for different measures and different types of EE savings. For example, new hardware upgrades contribute savings over their expected lifetimes, perhaps 15 years, whereas electricity savings from changing thermostat set-points are assumed to contribute savings over a much shorter period of time. City of Palo Alto Page 3 Figure 1 provides a summary of the annual EE goals and achievements since Fiscal Year (FY) 2011. The figure shows that actual CPAU EE achievements meet or exceed goals for most years. Figure 1. Electric Efficiency Goals and Achievements for 2011-2020.2 2 The sharp drop in savings in 2020 were lower than the goal as a result of delays in launching the direct install EE program targeting small to medium businesses and the home energy reports, challenges related to Covid-19 that have stopped or delayed projects, and overall load decline . Actual savings in 2018 and 2019 are calculated using a net to gross ratio of 0.85 to compare goals using identical underlying assumptions. Demand side management reports for these same years used an average net to gross ratio of 0.65 and as a result do not align with the actual savings shown in this graph. The net to gross ratio represents an estimate of the proportion of participants in a utility-run program who would have installed efficiency measures even without the utility-run program. A net to gross ratio of 0.85 means that 85% of program participants reduced consumption primarily as a result of their participation in the utility program, and would not have reduced consumption if the program had not been available. City of Palo Alto Page 4 In 2015 California passed a landmark piece of energy legislation called Senate Bill 350 (SB-350) the “Clean Energy and Pollution Reduction Act of 2015”. SB 350 reinforces California’s position as a leader in clean energy and greenhouse gas reduction and codified Governor Brown’s ambitious “50/50/50” plan to procure 50% of electricity from renewable resources, reduce petroleum use by 50%, and double building efficiency in both electric and natural gas end uses by 2030. The statute lists a variety of programs to achieve the do ubling of efficiency savings, including: 1) appliance and building standards; 2) utility programs that offer financial incentives, rebates, technical assistance and support to customers to increase EE; 3) programs that achieve EE savings through operational, behavioral and retrocommissioning activities; and 4) programs that save energy in final end uses through reducing distribution feeder voltage (i.e. conservation voltage reduction). In 2017, City Council adopted ambitious 10-year EE goals for 2018 to 2027, approximately 30% higher than the previous efficiency goals, and a corresponding 30% increase in efficiency spending. Given the declines in electricity sales since 2017 and large load declines from COVID, maintaining these higher reach goals is not being proposed for this goal cycle. Discussion CPAU has offered energy efficiency programs since the 1970s. Its Long -term Electric Acquisition Plan (LEAP), approved by City Council in March 2007 and last updated in 2018 as the Electric Integrated Resource Plan (EIRP), affirmed cost-effective energy efficiency as the highest priority resource, with the goal of reducing average customer bills. The portfolio of EE programs has evolved over time. Originally the programs focused on rebates for customers admin istered by CPAU staff, but now they include a combination of rebates and programs administered by third parties that provide EE audit and turnkey EE services to customers. Some of the notable programs in recent years include a comprehensive home efficiency audit and retrofit program that targets low income and multi-family residences, a new construction assistance program for commercial customers to increase building efficiency, and third party administered programs that offer turnkey efficiency services to businesses. Palo Alto also has an ongoing Program for Emerging Technologies to evaluate, test and implement innovative emerging technologies that could help customers manage or reduce energy and water use. Besides utility rebate programs, Palo Alto continues pursuing energy savings through its local building code. In December 2019, City Council adopted an Energy Reach Code which requires additional energy efficiency savings beyond California’s Title 24 building energy standards for non-residential mixed-fuel new construction projects3. The City’s Energy Reach Code has been in place since 2008 and has continued to evolve with California’s building standards (Title 24). As a reach code specific to only the City of Palo Alto, energy savings from this code a re savings that may be counted towards these EE goals. 3 Under Palo Alto’s current Energy Reach Code, additional efficiencies are not required of non -residential all- electric new construction projects. City of Palo Alto Page 5 From a supply resource planning perspective, CPAU has incorporated both historic EE savings as well as forecast EE savings (from Council-approved EE goals) when forecasting the aggregate customer loads for a 10-year planning period. Energy efficiency related savings impacted directly by utility programs over the past 10 years is estimated at 6.7% of 2020 loads, i.e. without such programs, Palo Alto’s electrical loads would have been 6.7% (64,500 MWh) h igher in 2020. Proposed Electric Efficiency Goals Staff proposes new annual electric EE targets at 0.5% of forecast electric load beginning in FY 2022, increasing to 0.75% in FY 2026 when the conservation voltage reduction program can be implemented. These proposed goals reflect staff’s anticipation that savings levels will take time to recover following the economic downturn. In addition, a few programs are in the process of transitioning to new vendors and this will also contribute to the trend of incre asing savings over time. The proposed goals are based on the results of a EE potential model that takes into account planned program offerings, expenditures, market saturation of energy efficient technologies, load forecast, and a planned conservation volt age reduction program following the city-wide deployment of Advanced Metering Infrastructure (AMI).Overall, these goals are similar to the annual electric EE targets adopted in 2012 (see Figure 2). The goals adopted in 2017 were based on an aggressive scenario that assumed an increase of 30% staffing and incentives as well as a growing electric load over time. With load decline, the 2017 goals are no longer economical and goals have been adjusted to reflect this change. Figure 3. Historic EE Savings and Proposed Annual Electric EE Goals on an Energy Basis. shows the actual historical EE savings and the proposed 2022 to 2031 EE goals. Further, the City’s energy efficiency potential model estimates a market potential lower than the adopted 2012 and 2017 goals and a smaller market potential with more stringent codes and standards4. Staff believes these goals are aggressive, but are achievable targets given low-cost energy efficiency technologies are approaching market saturation, so the market potential is declining. These proposed goals are also projected to be cost-effective based on both the model projections and past EE program costs. Savings from EE can be reported on a net basis, meaning they exclude energy impacts from free-riders (program participants who would have installed EE even without incentives), or on a gross basis, meaning they include impacts from program participants that are free-riders. The goals in Figure 4 are based on “net” EE savings rather than “gross” EE savings.5 This means they do not include the energy savings that would have occurred in the absence of utility incentives, and therefore most accurately reflect the EE savings attributable to CPAU’s programs. CPAU also excludes savings attributable to the state’s building and appliance standards. In order to 4 EE savings attributed to state mandated codes and standards are excluded from the EE potential for CPAU, and therefore also cannot count toward meeting its EE goals. 5 The 2022 – 2031 Goals assumes free-ridership at the measure level using an average net-to-gross (NTG) ratio of 0.85 except for low income and conservation voltage r eduction programs, where the assume is 1.0 (no free ridership). The NTG ratios are based on California statewide evaluation studies and are documented in Database of Energy Efficiency Results (DEER). Generally, mature, low-cost technologies tend to have higher free-ridership. City of Palo Alto Page 6 allow comparison with other utilities that set goals on a gross basis, the proposed annual goals in Figure 2 are shown as proposed (on a net basis without including codes and standards), as well as on a gross basis. Figure 2. Comparison of Proposed 2017 Electric EE goals and 2012 Electric EE Goals. City of Palo Alto Page 7 Below, Figure 3. Historic EE Savings and Proposed Annual Electric EE Goals on an Energy Basis. shows the reported EE savings as well as the proposed annual electric EE goals expressed in MWh. The big jump in 2012’s reported savings was due to t he completion of a significant EE project at a large commercial site, which is unlikely to be replicable. The sharp drop in savings in 2020 were lower than the goal as a result of delays in launching the direct install EE program targeting small to medium businesses, and the home energy report program, challenges related to Covid-19 that have stopped or delayed projects, and overall load decline. Impacts of the economic recession are expected to continue into 2021 with a gradual rebound beginning in 2022. Figure 3. Historic EE Savings and Proposed Annual Electric EE Goals on an Energy Basis. On a cumulative basis, the total EE savings from the proposed 2022 to 2031 targets represent 4.4% of the forecasted electric load in 2031. The cumulative impact of the annual targets for this 10-year period is shown in Figure 4. Importantly, some EE savings have a longer-lasting effect than others, as different EE measures have different useful life times. Measure life for City of Palo Alto Page 8 Light Emitting Diode (LED) bulbs can be up to 12 years, whereas behavioral savings last only last a few years. Due to the differences in EE savings persistence, the cumulative EE impact over the 10-year period is not equal to the sum of the annual EE goals for the 10 years. Figure 4. Proposed 2022-2031 Cumulative Electric EE Goals. Strategies for Achieving the Proposed EE Goals Achieving these EE goals will require the aggressive deployment of both ne w and existing programs, and developing program approaches to reach previously under -served sections of the energy efficiency market potential. While the proposed EE goals may appear small relative to past goals and the historical savings, the proposed goals will require excellent program execution and successful AMI implementation prior to launching a conservation voltage reduction program. In the past, staff has held a training seminar for facilities managers called Building Operator Certification. This training, if offered again, could help tap into potential energy efficiency savings for large commercial and industrial customers. Staff is in the process of soliciting third party program proposals targeting energy efficiency savings in the commercial and industrial (C&I) sectors. C&I programs have generated the majority of energy efficiency savings over time, so successful execution of these programs is critical to the success of reaching these goals. City of Palo Alto Page 9 Further, staff is in the process of launching Home Energy Reports to drive additional residential energy savings. This program launch has been delayed due to resource and technology constraints. Getting this program in place by 2022 will be critical to reaching the goals. In addition, once the City implements an Advanced Metering Infrastructure (AMI) backbone of a smart-grid system, staff plans to start a conservation voltage reduction program using the AMI infrastructure on its 68 primary feeders. Potential savings from this program are estimated to be up to 1% of the City’s annual electricity load and are targeted to start in 2026. These plans are subject to Council consideration and approval. Staff is also investigating a demand reduction pilot, which could potentially contribute EE savings from sm art devices like thermostats and other behind-the-meter technologies. This evolution of CPAU’s EE portfolio is consistent with the general consensus among utilities that new approaches are needed to reach increasingly aggressive EE targets as traditiona l EE programs approach market saturation limitations. Projected Electric EE Program Costs Funding for EE programs comes from a mandated Public Benefit (PB)6 surcharge of 2.85% of the electric utility bill for all customers. To meet the proposed EE goal s, staff estimates an annual EE budget of $1.9M to $2.4M per year from 2022 to 2031. This projected EE program budget is anticipated to be funded roughly 65% by the annual PB collections. Figure 5 shows the actual electric EE program expenditures for FY 2008 through FY 2019, estimates for FY20 and FY21, and the estimated annual EE budget between 2022 and 2031. 6 Locally owned municipal utilities like CPAU must collect Public Benefits funds as required by section 385 of the Public Utilities Code, to be used on cost-effective energy efficiency and conservation, low income programs, investments in renewable energy resources and technologies, and research and development. City of Palo Alto Page 10 Figure 5. Actual and Projected Electric EE Program Costs. Retail Rate & Average Customer Bill Impact of the Proposed Electric EE Goals EE programs impact retail rates in two ways. First, a lower electric load means that fixed costs (capital investments and fixed operating costs to run the electric utility) must be distributed over a lower electric sales volume, thereby increasing the average electric retail rate. Second, the use of funds to support EE programs increases the revenue requirements for the electric utility. Overall, these proposed goals are estimated to amount to a cumulative increase in the retail rate of approximately 3.5% by the year 2031. The majority of this retail rate increase is due to the cumulative load reduction from the proposed 10-year EE goals. Increased charging of electric vehicles, electrification of natural gas appliances, and other electr ic load growth could mitigate the retail rate impact of the EE programs. While rates increase, total bills are expected to be reduced over the lifetime of the EE savings. City of Palo Alto Page 11 Timeline, Resource Impact, Policy Implications (If Applicable) This report contains preliminary estimates of the costs of achieving the proposed electric and gas EE goals. The detailed budget plan and staffing needs to meet the annual EE goals will be part of the annual City budgeting process. The annual budget will present the co sts for both internally administered, as well as contractor supported, efficiency programs. Adoption of the proposed electric 10-year EE goals will replace the 2017 10-year electric EE goals and will inform the EE program planning and load forecasting f or the next four years. These goals will also be included in the Electric Utility Integrated Resource Plan, and the City’s Sustainability Implementation Plan. The proposed 2022 - 2031 electric EE goals are consistent with the Utilities Strategic Plan, and the City’s S/CAP. Stakeholder Engagement Energy efficiency is included as a key action for the Sustainability and Climate Action Plan (S/CAP), and stakeholder engagement has taken place as part of the development of that plan. Staff does not typically do stakeholder outreach in developing plans but does assess market potential of various programs and discusses available efficiency measures with industry experts. Outreach related to specific efficiency programs includes direct engagement with key account customers, monthly newsletters, home efficiency advisor phone support, utility bill inserts, online webinars and workshops and social media posts. Environmental Review The UAC’s recommendation that Council approve the 2021 10-year electric EE goals does not require California Environmental Quality Act review, because the plan does not meet the definition of a project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5), as an administrative governmental activity which will not cause a direct or indirect physical change in the environment. Attachments: • Attachment A: Presentation March 3, 2021 www.cityofpaloalto.org City of Palo Alto Utilities10-Year Electric EnergyEfficiency Goals 2022-2031 Utilities Advisory Commission 1 • CITY OF PALO ALTO Staff: Christine Tam; Lena Perkins; Lisa Benatar and Micah Babbitt Overview •Background on 10-year electric EE goals •Review the proposed 10-year electric efficiency goals •Comparison of proposed and previous goals •Impact on retail rates and average bills •Action: Recommend that Council adopt the proposed 10- year energy efficiency goals 2~CITY OF ~PALO ALTO 10-year electric energy efficiency (EE) goals •Required to update electric goals every 4 years (Updated in 2007, 2010, 2012, 2017) •EE programs funded by state-mandated Public Benefits surcharge •EE programs required to be cost-effect i ve •Adoption of updated goals required by March 15, 2021 and submitted to CEC within 60 days 3~CITY OF ~PALO ALTO Past EE goals & achievements •Historically meet and exceed goals •Adopted 30% more aggressive “reach” goals for 2018 – 2027 •Sharp savings drop driven by program launch challenges and Covid impacts 4 1.4% □A ctua l Sav in gs Percentages represent EE sav ings re lative to load ♦2008 -20 1 7 Goa l - +20 1 1 -2020 Goa l 1.2% ♦2014 -2023 Goa l ... 2018 -2027 Goa l 1.0% ---- 0 .8 % ------------ 0 .6% ~ - ,,Jt---- ~ -.... .... .... .... - - - -- -- 0 .4% -~ --... ~ 0 .2% 0 .0 % 2008 2009 2010 201 1 2012 2013 20 14 2015 201 6 2017 2018 2019 202 0 2021 ~CITY OF ~PALO ALTO s s s s 2021 Electric EE Goal Development •Model developed by consultant and used by all CA POUs •Model assesses technical, economic, and market potential •Accounts for past EE achievements, projected electric supply cost, retails rates, and EE costs to calculate EE Cost Effectiveness •Economic recovery from COVID-19 factored into the goals 5~CITY OF ~PALO ALTO Techn ica l Utility Data ·Rates • Forecasts • Avoided oost s 1• Economic -■1 Market • DSM ach ~vements Customer Data I. -I • Customer segmenta1ion •Technology density • Technology saturation • A11r.1reness • Willingness to pay Measure Data • Measure list • Savings impacts • Measure ana a(lmJn costs • Measure ure • Incentives Measure Availability • Yearly bUIICllng SIOCk • 0Irrerence oe1ween oasellne measure and efficient measure • Codes and standards Savings Potential by End Use •Non-Residential Lighting, HVAC, Comprehensive major drivers of savings goals •Conservation Voltage Reduction program expected to contribute significant savings beginning in 2026 once Advanced Metering Infrastructure is in place 6 Potential Savings by End Use 100% 90% 0.4% 17% 17% 80% "' 70% 0.0 C ·s; 60% re (f) ._ 2% 12% 0 Q) 50% 0.0 re ...... 9% 9% C 40% Q) u '-- Q) c.. 30% 20% 10% 0% 2022 2023 2024 2025 2026 2027 2028 2029 2030 Year ■ Non-Residential Lighting ■ Non-Residential HVAC ■ Non-Residential Comprehensive ■ Residential Home Energy Reports ■ Conservation Voltage Reduction ■ All Other ~CITY OF ~PALO ALTO 12% 2031 Proposed and previous Goals •Economic downturn recovery factored into 2022 – 2025 •Conservation Voltage Reduction (CVR) expected to begin 2026 once Advanced Metering Infrastructure in place CVR Program 7 1.0% 0.9% 0.8% 0.7% 0 .6% ••-~•-------4· ....... ---•-~•------✓------✓ 0.5% 0 .4% 0.3% 0.2% 0 .1% Percentages represent EE savings relative to load 0.0% • ~2022 -2031 Goals ... 2018 -2027 Goals ~2014 -2023 Goals 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 ~CITY OF ~PALO ALTO Proposed goals in MWh •2020 drop driven by program launch challenges for home energy reports, small and medium business program and Covid impacts •2021 savings estimated to be lower than 2020 8 MWh 12,500 10,000 7 ,500 5,000 2,500 I 0 +--L-r-"--,... 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 ~CITY OF ~PALO ALTO Cumulative Savings Potential •Cumulative savings largely driven by long lived non-residential EE measures •Cumulative savings account for EE measures effective useful life 9 40,000 35,000 30,000 25,000 ..c S 20,000 2 15,000 10,000 5,000 0 2022 Cumulative Net Market Potential by Sector All Sectors Energy Potential (MWh) and% of Sales 2023 2024 2025 2026 2027 2028 2029 2030 2031 -Non-Res Cumulative Market Potential 5.0% 4.5% 4.0% 3.5% Vl ~ C'IJ V) 3.0% ..c $ (,'.) 2 .5% ro ::, C: 2 .0% ~ .... 0 1.5% * 1 .0% 0.5% 0.0% -Res Cumulative Market Potential CVR Potential (If Claimed) -Total Cumulative Potential as a% of Total Sales ~CITY OF ~PALO ALTO Impact on retail rates and average customer bills •Average customer bills are expected to decrease over the life of the energy efficiency measures •Retail rates are estimated to increase up to 3.5% by 2031 •Increased EV charging or load growth from building electrification could mitigate some of the retail rate impact 10~CITY OF ~PALO ALTO Proposed Motion Proposed Motion: The Utilities Advisory Commission recommends that Council approve the proposed annual and cumulative electric efficiency goals for the period 2022 to 2031 as shown in the table here Electric (%) Electric MWh 2022 0.50%4,300 2023 0.50%4,500 2024 0.55%4,900 2025 0.60%5,300 2026 0.75%6,600 2027 0.75%6,600 2028 0.75%6,500 2029 0.80%6,900 2030 0.80%6,900 2031 0.80%6,900 Cumulative 10-year EE Goal 4.40%37,940 Annual Electric Energy Efficiency Goals (% of total City customer usage) 11~CITY OF ~PALO ALTO Christine Tam, Lena Perkins, Lisa Benatar & Micah Babbitt Senior Resource Planner, Senior Resource Planner, Utility Program Services Manager, Resource Planner christine.tam@cityofpaloalto.org, lena.perkins@cityofpaloalto.org, lisa.benatar@cityofpaloalto.org, micah.babbitt@cityofpaloalto.org 12 CITY OF PALO ALTO City of Palo Alto (ID # 11884) Utilities Advisory Commission Staff Report Report Type: New Business Meeting Date: 3/3/2021 City of Palo Alto Page 1 Summary Title: FY 2022 Gas Financial Plan and Rates Title: Staff Recommendation That the Utilities Advisory Commission Recommend the City Council Adopt a Resolution Approving the Fiscal Year 2022 Gas Utility Financial Plan, Including Proposed Transfers and an Amendment to the Gas Utility Reserve Management Practices, and Increasing Gas Rates by Amending Rate Schedules G -1 (Residential Gas Service), G -2 (Residential Master-Metered and Commercial Gas Service), G -3 (Large Commercial Gas Service), and G -10 (Compressed Natural Gas Service) From: City Manager Lead Department: Utilities Recommendation Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council adopt a resolution (Attachment A): a.Approving the fiscal year (FY) 2022 Gas Utility Financial Plan (Attachment B); and b.Transferring up to $3.9 million from the Rate Stabilization Reserve (RSR) to the Operations Reserve at the end of FY 2021; and c.Transferring $4.542 million from the Rate Stabilization Reserve to the Cap-and-Trade Program Reserve at the end of FY 2021; and d.Amending the Gas Utility Reserve Management Practices relating to the Cap-and-Trade Program Reserve (as set forth in the Financial Plan) (Attachment C); and e.Increasing gas rates by amending Rate Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas Service), and G-10 (Compressed Natural Gas Service) (Attachment D). Executive Summary The FY 2022 Gas Utility Financial Plan includes projections of the utility’s costs and revenues for FY 2022 through FY 2026. Gas utility costs are made up of supply -related costs (27 percent of costs in FY 2020), which are collected through a supply rate that varies monthly, and distribution-related costs (73 percent of costs in FY 2020), which are collected through a distribution rate that is typically adjusted not more than one time per year . Distribution rates were last increased on July 1, 2020, which resulted in a roughly 2 percent increase in the total system average gas rate (the supply rates plus the distribution rates). Staff: Eric Keniston and Lisa Bilir City of Palo Alto Page 2 The proposed FY 2022 Gas Utility Financial Plan includes an increase in distribution rates effective July 1, 2021 and will result in a 3 percent increase to the total system average gas rate if supply rates remain unchanged. Additional 5 percent increases to the total system average gas rate are projected over the next three years. CIP expenditures for the last several years have been lower than normal while the City was completing the Upgrade Downtown project, and much of this increase is due to the Gas Utility resuming ongoing main replacement projects and the cross-bore safety verification program. In addition, staff proposes a transfer to the Operations Reserve of up to $3.9 million from the Rate Stabilization Reserve to ensure adequate operating reserves. The Rate Stabilization Reserve is projected to be at zero balance by the end of FY 2021, consistent with the Council- adopted Reserves Management Practices, which specify that funds are only intended to be held in the Rate Stabilization Reserve to manage the trajectory of future year rate increases and which should be completely used by the end of the financial planning period. A transfer of $4.542 million to the Cap-and-Trade Program Reserve from the Rate Stabilization Reserve is also proposed to account for revenues related to the State’s Cap and Trade program that are required to be used for specific purposes. The City’s natural gas rates are based on the 2019 Natural Gas Cost of Service and Rates Study, updated with current and proposed operating costs. With the onset of the COVID-19 pandemic, usage amongst businesses has dropped to reflect people working and staying at home rather than going to the workplace, as well as restrictions to business operations. Businesses have been forced to operate at minimum staffing conditions or fully remote while the pandemic continues. City of Palo Alto staff have worked at reducing cost increases, and some capital project work has been moved out or restructured to keep costs from rising too much during this time. However, costs related to the Gas Utility’s resumption of main replacement projects and the cross-bore safety verification program are increasing. In order to move towards full cost recovery while minimizing rate impacts in light of pandemic-related economic challenges, staff recommends a distribution rate increase to all customer classes of 5%, which staff estimates will result in a 3% system average rate increase . If, after the pandemic, usage and/or spending looks to be moving in a different direction, staff will suggest a re-balancing of rates at that time. While staff is recommending that the distribution component of the rates be increased by 5%, distribution rates comprise about 70% of the overall rate, which consists of commodity (supply) and distribution components. Supply-related costs (the cost of the natural gas itself, gas transmission, and gas environmental charges) are a fluid component of the Gas Utility’s expenses. It not possible to precisely predict commodity rates, which make up approximately 30% of overall retail gas rates. Market prices are monitored monthly and automatically incorporated into monthly supply rate adjustments, which are passed directly to customers as a line item on their utility bills. City of Palo Alto Page 3 Because it is not possible to exactly predict what supply rates will be during the planning horizon, the overall rate increases (commodity plus distribution) referenced in this report assume that the commodity portion of the overall rate remains unchanged. The net effect is a proposed 3% overall rate increase. Recent market indications have led staff to project supply cost increases of around 4.1 percent annually for the forecast horizon , primarily due to increasing gas transmission and environmental charges. If these increases did occur, it would result in an estimated additional 1.2% percent increase in the overall customer bill. Table 1: Revenue and Rate Increases by Customer Class Cost of Service Analysis FY 2022 Rate Increase needed for Distribution Charges Assumed Commodity Rate Changes Net Rate Increase for Combined Commodity and Distribution Charges G1 - Residential 5% 0% 3% G2 - Small Commercial 5% 0% 3% G3 - Large Commercial 5% 0% 3% TOTAL 5% 0% 3% Figure 1 below shows the primary drivers for the proposed rate change, which are almost equally split between increasing Capital Improvement (CIP) cost and increases in Operations expenses. The increases are discussed in greater depth in the attached FY 2022 Gas Financial Plan: City of Palo Alto Page 4 Figure 1: Allocation of Distribution Rate increase Background Every year staff presents the Utilities Advisory Commission 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 Practice s describing the reserves for each utility and the management practices for those reserves. The City’s gas is purchased from a variety of marketers who source gas from throughout the Western United States. The City then pays Pacific Gas and Electric (PG&E) to transport the gas across its gas transmission system to Palo Alto, which is then delivered to customers through Palo Alto’s gas distribution system. The Gas Utility’s costs are divided into two main categories: gas supply costs (which includes the cost of the gas itself, the cost of transmitting the gas to Palo Alto, and environmental costs 1) and the costs of running the business and operating the distribution system. As noted above, gas supply costs vary with the market, and the costs are passed through to customers through a gas supply rate component that varies monthly. The UAC reviewed preliminary financial forecasts at its December 2, 2020 meeting. At that meeting, staff also projected a distribution rate increase that resulted in a 3% increase to the total system gas rate (with supply rates assumed to stay flat and distribution rates increasing 5%). Discussion 1 These are the costs of complying with the State’s Cap and Trade system and procuring offsets under the City’s Carbon Neutral Gas program. City of Palo Alto Page 5 Staff’s annual assessment of the financial position of the City’s gas utility is completed to ensure adequate revenue to fund operations and to ensure that the City’s rates comply with cost-of- service requirements set forth in the California Constitution and applicable statutory law. The assessment includes making long-term projections of market conditions, of costs associated with the physical condition of infrastructure, and of other factors that could affect utility costs. Rates are then proposed that will be adequate to recover projected costs. Proposed Actions for FY 2021 and FY 2022: The FY 2022 Gas Utility Financial Plan includes the following proposed actions: 1. Amend gas rate schedules (see Attachment D) to increase distribution rates by 5 percent, resulting in an estimated 3 percent increase on overall rates. 2. Transfer up to $3.9 million from the Rate Stabilization Reserve (RSR) to the Operations Reserve. 3. Transfer $4.542 million from the RSR to the Cap-and-Trade Program Reserve; and 4. Amend the Gas Utility Reserve Management Practices (as shown in redline in Attachment C). The reserve transfers and proposed changes to the Reserve Management Practices will enable staff to both maintain sufficient funds in the Gas Operations Reserve while establishing a Cap- and-Trade Program Reserve to account for revenues associated with the State’s Cap and Trade Program, revenues which are required to be used for specific purposes. All of these proposed actions are described in more detail below and in the FY 2022 Gas Financial Plan (Attachment B). Proposed Gas Rates Staff proposes to adjust gas rates as shown in Table 2 and Table 3 below, effective July 1, 2021. These changes are projected to increase the total system average gas rate (total of supply and distribution) by roughly 3 percent for all classes. These rate changes are included in the proposed amended rate schedules in Attachment D. Table 2: Current and Proposed Monthly Service Charges Rate Schedule Monthly Service Charge ($/month) Change Current (as of 7/1/20) Proposed for FY 2022 ($) (%) G-1 (Residential) $10.37 $10.89 $0.52 5.0% G-2 (Small Commercial) 96.05 100.85 4.80 5.0% G-3 (Large Commercial) 439.46 461.43 21.97 5.0% G-10 (CNG) 64.96 68.21 3.25 5.0% City of Palo Alto Page 6 Table 3: Current and Proposed Gas Distribution Charges Change Current (as of 7/1/19) Proposed for FY 2022 ($) (%) G-1 (Residential) Tier 1 Rates $0.5038 $ 0.5290 $0.0252 5.0% Tier 2 Rates 1.2882 1.3526 0.0644 5.0% G-2 (Residential Master-Metered and Small Commercial) Uniform Rate 0.6617 0.6948 0.0331 5.0% G-3 (Large Commercial) Uniform Rate 0.6551 0.6879 0.0328 5.0% G-10 (Compressed Natural Gas) Uniform Rate 0.0108 0.0113 0.0005 5.0% Bill Impact of Proposed Rate Changes Table 4 shows the impact of the proposed July 1, 2021 rate changes on various levels of residential bills. The average increase for the residential class is roughly 3 percent on average based on last year’s commodity prices. As the price of commodities changes monthly, the actual increase may be higher or lower than the 3% average. Table 4 shows a representative Winter period (November thru March) and Summer period (April through October) bill comparison: Table 4: Impact of Proposed Gas Rate Changes on Residential Bills Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change $/mo. % Winter (Using November 2020 commodity prices) 30 $ 41.88 $ 43.15 $ 1.27 3.0% 54 (median) 67.09 68.97 1.88 2.8% 80 110.08 113.40 3.32 3.0% 150 238.51 246.34 7.83 3.3% Summer (Using October 2020 commodity prices) 10 $ 20.85 $ 21.62 $ 0.77 3.7% 18 (median) 29.23 30.20 0.97 3.3% 30 49.13 50.79 1.66 3.4% 45 76.61 79.24 2.63 3.4% City of Palo Alto Page 7 Table 5 shows the impact of the proposed July 1, 2021 rate changes on various representative commercial customer bills. The overall increases for the G-2 and G-3 classes are projected to be about 3 percent on an annual basis. Table 5: Impact of Proposed Gas Rate Changes on Commercial Bills (Using December 2020 commodity prices) Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change % 500 685 706 3.1% 5,000 5,986 6,156 2.8% 10,000 11,875 12,211 2.8% 50,000 59,005 60,665 2.8% FY 2021 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years Table 6 shows the projected rate adjustments over the next five years and their impact on the annual median residential gas bill (54 therms per month in winter, 18 therms per month in summer). Table 6: Projected Rate Adjustments, FY 2022 to FY 2026 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Gas Utility 3% 5% 5% 5% 3% Estimated Bill Impact ($/mo)* $1.35 $2.20 $2.31 $2.43 $1.53 * estimated impact on median residential gas bill, which is currently $43.40 for CY 2020 One of the main drivers for the increase in the Gas Utility’s short-term costs (and therefore rates) over the next several years are increases in capital improvement costs to maintain a safe and reliable system. FY 2017 included replacements of gas mains on University Avenue, a project that has evolved into the Upgrade Downtown project, involving a coordinated replacement of several different types of infrastructure to avoid multiple disruptions to the business district. This was a multi-year planning effort, completed in 2019, which did not allow for design of other new projects. Also, as government agencies regionally and nationally spend more on infrastructure improvement, contractor bids for underground construction have risen greatly from where they were in years past. This current financial plan works to address these challenges in a way that will allow City of Palo Alto Utilities (CPAU) to meet its gas main replacement (GMR) needs. The next focus of the GMR program will be the replacement of all Polyvinyl Chloride (PVC) mains with Polyethylene (PE) mains. CPAU installed PVC pipes from the early 1970s to mid-1980s. Some of the City’s PVC pipe is approaching 50 years of service, and according to industry data, PVC pipes have a much higher leakage rate than PE mains after 20 years of service due to potential disbandment of fittings and joints. This financial plan includes approximately $7 to 9 million every other year for City of Palo Alto Page 8 main replacement construction instead of $5 to 6 million annually, starting in FY 2021. This shift to larger main replacement construction projects every other year will slightly lengthen the amount of time needed to replace all PVC pipes in the system but will ideally attract more contractors and better bid pricing on the larger projects. Additionall y, this main replacement project schedule for gas will be staggered with water and wastewater (water and wastewater construction every even year and gas construction every odd year), which will ease scheduling difficulties for inspection coverage due to shared inspection staff across water, wastewater, gas, and large development services projects. This arrangement is likely to be a short-term solution (3-5 years) until project capacity can be increased and upward pressure on utility rates has eased. Table 7 below shows the reserve balance changes for each reserve from FY 2021 and projected through FY 2026. City of Palo Alto Page 9 Table 7: Operations, Rate Stabilization and CIP Reserve Starting and Ending Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contributi on To/(From) Reserves, and Reserve Guideline Levels for FY 2021 to FY 2026 ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Starting Reserve Balances 1 Operations Reserve 13,450 10,782 12,645 7,214 9,238 7,970 2 CIP Reserve 3,820 3,820 - - 1,000 - 3 Cap and Trade - 5,936 7,458 9,228 11,271 13,573 4 Rate Stabilization 8,419 - - - - - Revenues 5 Total Revenues 37,368 42,334 45,804 49,160 52,135 53,904 6 Cap and Trade 1,394 1,522 1,770 2,043 2,302 2,565 Transfers 7 Operations Reserve 3,877 3,820 - (1,000) 1,000 (2,000) 8 CIP Reserve - (3,820) - 1,000 (1,000) 2,000 9 Cap and Trade 4,542 10 Rate Stabilization (8,419) Expenses 11 Non-CIP Expenses (34,630) (39,618) (41,518) (41,875) (43,106) (43,584) 12 Planned CIP (9,283) (4,674) (9,717) (4,261) (11,297) (4,150) Ending Reserve Balances 1+5+7+11+12 Operations Reserve 10,782 12,645 7,214 9,238 7,970 12,141 2+8 CIP Reserve 3,820 - - 1,000 - 2,000 3+6+9 Cap and Trade 5,936 7,458 9,228 11,271 13,573 16,138 4+10 Rate Stabilization - - - - - - Operations Reserve Guidelines 13 Minimum 6,439 6,512 6,825 6,884 7,086 7,297 14 Maximum 12,879 13,025 13,650 13,767 14,172 14,593 CIP Reserve Guidelines 15 Minimum 1,770 1,725 1,920 1,775 1,989 1,856 16 Maximum 8,848 8,627 9,601 8,874 9,946 9,280 Figures 2 below illustrates the projected long run changes in the Gas Utility’s costs. Cost increases over the FY 2016 to FY 2026 time period are mainly from commodity cos ts, followed by operations and capital expenses. City of Palo Alto Page 10 Figure 2: FY 2016, FY 2022 and FY 2026 costs * Note that FY 2022 and FY 2026 Capital Investment costs are displayed as an average of two years’ cost to reflect the staggered main replacement schedule. Over the longer term, gas commodity costs are the most variable factor in customer gas bills, being subject to market forces, and are currently projected to grow by about 4 percent per year between FY 2022 and 2026. Much of this has to do with increased cost projections related to cap-and-trade allowance costs, carbon neutrality costs as well as transportation. Operations costs are projected to increase at 3 to 4 percent annually, partially due to inflation and salary and benefit increases, and partially due to a large one-time increase in costs to pay for phase two of a cross-bore safety verification program. The cross-bore safety program ensures that gas pipelines have not crossed through sewer laterals, which is rare but possible during trenchless installation. This is referred to as a “cross-bore,” and while they are very rare, if they exist, they pose a risk of gas leaks if a plumber uses a cutting tool to clear a sewer line and accidentally cuts the gas line. The project will video inspect, determine, and repair any unintended conflicts between gas service pipelines and sewer laterals. Phase two of this program is estimated to require $1 million per year for the next two years, although the project may require additional funding depending on what inspections show. The COVID pandemic of 2020 has resulted in gas usage decreasing to levels similar to what was seen in the 2014/2015 drought. Declines have come mainly in the commercial sectors as a result of many businesses operating staff remotely. The impact to FY 2020 was a drop of about 2.6% from projections, and projections for FY 2021 assumed similar losses of 2 to 4%. However, City of Palo Alto Page 11 monthly consumption during the early part of FY 2021 showed loses of between 6 to 10%, indicating that gas usage was being impacted much more drastically than initially projected. The ongoing nature of the pandemic, as well as usage declines similar to what has been seen in the electric utility, leads to questions of how long the trend of reduced consumption in gas will last. Staff worked with Northern California Power Agency (NCPA), the City’s electric load forecaster, to incorporate UCLA’s Anderson School GDP forecast into its electric load forecast for Palo Alto, which estimates the economic trend impacts to last through December 2020. The same recovery pattern was used in Figure 3 below to forecast various possible levels of gas usage recovery. As seen with prior economic and drought gas usage declines in the past, it is likely that consumption will not come back to pre -conservation/pandemic levels but will likely stabilize closer to the longer-run decline in gas usage seen over the years. Further changes, such as the voluntary replacement of gas appliances with electric appliances, building electrification of new construction as mandated by the 2019 Reach Code, and customer behavior are also expected to lower long run usage, and this forecast will be revised accordingly as more customers adopt these measures.2 Staff has also run preliminary estimates of the impacts of Sustainability and Climate Action Plan (S/CAP) goals on gas use and presented them to the UAC in January of 2021.3 Based on billing data through December 2020, which has shown some recovery with the return of winter heating, the monthly usage is matching closer to the ‘Medium Recovery’ (about a 6 to 7% usage decline) line shown in Figure 5, and this is the scenario utilized for the proposed rate projections. The ‘Deep Recovery’ (about a 10% usage decline) line would result in roughly $1 million in additional lost revenues and may require corresponding expense cuts if future sales do not recover in a faster fashion. It is too early in the winter heating season to tell what the trend will continue to be. However, rapidly declining gas consumption will put upward pressure on rates, as a generally increasing cost to operate and distribute gas will be spread across fewer units of sale. 2 The City’s Sustainability and Climate Action Plan (S/CAP) is currently being updated. As building electrification goals in the S/CAP are updated, they will be modeled in this load forecast. 3 January 6, 2021 UAC Meeting, Discussion of Projected Electrification Impacts on Gas Utility System Averag e Rates: http://cityofpaloalto.org/civicax/filebank/documents/79748 City of Palo Alto Page 12 Figure 3: Forecast Gas Consumption Gas Bill Comparison with Surrounding Cities 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 2020 (to illustrate a summer month bill) and December 2020 (to illustrate a winter month bill). The annual gas bill for the median residential customer for calendar year 2020 was $523.59, about 12% lower than the annual bill for a PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased substantially to collect for needed system improvements for pipeline safety and maintenance. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which includes the surrounding communities. Table 8: Residential Monthly Natural Gas Bill Comparison ($/month) Season Usage (therms) Palo Alto PG&E Zone X % Difference Winter (December 2020) 30 $ 40.97 49.66 -17.5% (Median) 54 65.45 92.48 -29.2% 80 106.09 149.00 -28.8% 150 232.40 301.19 -22.8% Summer (July 2020) 10 $ 19.31 14.07 37.3% (Median) 18 26.46 26.77 -1.2% 30 44.51 49.86 -10.7% 45 69.69 78.72 -11.5% Table 99 shows the monthly gas bills for commercial customers for various usage levels for rates in effect as of December 2020. Bills for CPAU customers at the usage levels shown can vary City of Palo Alto Page 13 from 12% lower to 15% higher for 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 higher distribution rates as the 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 December 2019) Usage (therms/mo) Gas Bill ($/month) % Difference Palo Alto PG&E 500 685 718 (5%) 5,000 5,986 6,831 (12%) 10,000 11,875 12,045 (1%) 50,000 59,005 51,419 15% Cap and Trade Program Reserve The Global Warming Solutions Act of 2006, also known as Assembly Bill (AB) 32, authorized the California Air Resources Board (CARB) to develop regulations to lower the state’s greenhouse gas (GHG) emissions to 1990 levels by 2020. CARB developed a cap -and-trade program as one of the strategies to achieve the 2020 goal. Entities with emissi ons are required to hold enough allowances (an allowance being equivalent to one metric ton of greenhouse gas, or CO2e) to cover its emitted output in a given year, also called its ‘compliance obligation.’ In addition, certain entities, and public power agencies, such as Palo Alto, have been distributed free allowances to reduce the rate impacts to customers from the purchase of required allowances. Revenues from the auction sale of allowances in each utility must be used exclusively for the benefit of the ratepayers in that utility. The City Council has adopted a policy on the use of allowance proceeds (Resolution 9487), with expressed preference that revenues be used for programs and projects rather than being returned to ratepayers in the form of a bill rebate. Per the current regulations, the utility must either spend or rebate the funds received in any given year within 10 years (for example, funds received in 2020 must be spent by 2030, etc.). To date the Cap-and-Trade revenues have been tracked internally and placed in the Rate Stabilization Reserves. Staff is seeking to account for these funds (currently $4.5 million) out in a separate reserve for ease of accounting and clarity. Timeline The Finance Committee is scheduled to review the FY 2022 Gas Financial Plan in March or April 2020. The City Council will consider adopting the Financial Plan, including the updated Reserve Management Practices, and rate adjustments as part of the FY 2022 budget review and adoption process. If Council approves the proposed rate changes, they will become effective July 1, 2021. City of Palo Alto Page 14 Resource Impact Normal year sales revenues for the Gas Utility are projected to increase by roughly 3 percent or $1.2 million as a result of the proposed rate increases, not including fluctuations in commodity revenue/cost. The FY 2022 Budget is being developed concurrent with these rates and, depending on the final rates, adjustments to the budget may be necessary a t a later time. See the attached FY 2022 Gas Financial Plan for a more comprehensive overview of projected cost and revenue changes for the next five 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 the California constitution and industry-accepted cost of service principles. Stakeholder Engagement The UAC reviewed preliminary financial forecasts at its December 2, 2020 meeting, and the Finance Committee reviewed the preliminary forecasts at its February 16, 2021 meeting. Staff and the UAC’s recommendation on the FY 2022 gas rate increases will go to the Finance Committee in April and be presented to City Council in June during the budget adoption process. Environmental Review The Utility Advisory Commission’s review and recommendation to Council on the FY 2022 Gas Financial Plan 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: • Attachment A: Resolution • Attachment B: FY 2022 Gas Financial Plan • Attachment C: Gas Reserve Management Practices • Attachments D 1-4 • Attachment E: Presentation Attachment A * NOT YET APPROVED * 6055486 Resolution No. _________ Resolution of the Council of the City of Palo Alto Approving the Fiscal Year 2022 Gas Utility Financial Plan, Including Proposed Transfers and an Amendment to the Gas Utility Reserve Management Practices, and Increasing Gas Rates by Amending Rate Schedules G-1 (Residential Gas Service), G-2 (Residential Master-Metered and Commercial Gas Service), G-3 (Large Commercial Gas Service), and G- 10 (Compressed Natural Gas Service) 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. 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. D. On ____, 2021, 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. The Council hereby adopts the FY 2022 Gas Utility Financial Plan. SECTION 2. The Council hereby approves the transfer of up to $3.9 Million from the Rate Stabilization Reserve to the Operations Reserve, and up $4.542 Million from the Rate Stabilization Reserve to the Cap and Trade Program Reserve, as described in the FY 2022 Gas Utility Financial Plan approved via this resolution. SECTION 3. The Council hereby approves the amendments to the Gas Utility Reserves Management Practices relating to the Cap and Trade Program Reserve. Attachment A * NOT YET APPROVED * 6055486 SECTION 4. 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, 2021. SECTION 5. 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, 2021. SECTION 6. 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, 2021. 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, 2021. SECTION 8. 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 gas 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 9. 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. // // // // // // // Attachment A * NOT YET APPROVED * 6055486 // SECTION 10. The Council finds that approving the Financial Plan and amending the Gas Utility Reserves Management Practices does not meet the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative governmental activity which will not cause a direct or indirect physical change in the environment, and therefore, no environmental assessment is required. The Council finds that 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 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: ___________________________ ___________________________ Assistant City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services FY 2022 GAS UTILITY FINANCIAL PLAN FY 2022 TO FY 2026 Attachment B GAS UTILITY FINANCIAL PLAN January 2021 2 | Page GAS UTILITY FINANCIAL PLAN FY 2022 TO FY 2026 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 .................................................................................. 7 Section 3: Detail of FY 2021 Rate and Reserve Proposals ........................................................ 8 Section 3A: Rate Design ............................................................................................................... 8 Section 3B: Current and Proposed Rates ..................................................................................... 9 Section 3C: Bill impact of Proposed Rate Changes .................................................................... 11 Section 3D: Proposed Reserve Transfers ................................................................................... 11 Section 4: Utility Overview .................................................................................................. 13 Section 4A: Gas Utility History ................................................................................................... 14 Section 4B: Customer Base ........................................................................................................ 15 Section 4C: Distribution System ................................................................................................. 16 Section 4D: Cost Structure and Revenue Sources ...................................................................... 17 Section 4E: Reserves Structure ................................................................................................... 17 Section 4F: Competitiveness ...................................................................................................... 18 Section 4G: Gas Supply Rates .................................................................................................... 19 Section 5: Utility Financial Projections ................................................................................. 20 Section 5A: Load Forecast .......................................................................................................... 20 Section 5A: FY 2015 to FY 2019 Cost and Revenue Trends ........................................................ 22 Section 5B: FY 2019 Results ....................................................................................................... 23 Section 5C: FY 2020 Projections ................................................................................................. 24 Section 5D: FY 2021-FY 2025 Projections .................................................................................. 24 Section 5E: Risk Assessment and Reserves Adequacy ............................................................... 27 GAS UTILITY FINANCIAL PLAN January 2021 3 | Page Section 5F: Long-Term Outlook ................................................................................................. 28 Section 6: Details and Assumptions ..................................................................................... 32 Section 6A: Gas Purchase Costs ................................................................................................. 32 Section 6B: Operations .............................................................................................................. 35 Section 6C: Capital Improvement Program (CIP) ....................................................................... 36 Section 6D: Debt Service ............................................................................................................ 38 Section 6E: Equity Transfer ........................................................................................................ 39 Section 6F: Revenues ................................................................................................................. 40 Section 6G: Communications Plan ............................................................................................. 40 Appendices ......................................................................................................................... 42 Appendix A: Gas Financial Forecast Detail ................................................................................ 43 Appendix B: Gas Utility Capital Improvement Program (CIP) Detail ......................................... 44 Appendix C: Gas Utility Reserves Management Practices ......................................................... 45 Appendix D: Description of Gas Utility Cost Categories ............................................................ 49 Appendix E: Gas Utility Communications Samples .................................................................... 50 GAS UTILITY FINANCIAL PLAN January 2021 4 | Page SECTION 1: DEFINITIONS AND ABBREVIATIONS ABS: Acrylonitirile butydene styrene, a plastic gas main material AMI: Advanced Metering Infrastructure 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 January 2021 5 | Page SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Gas Utility for the next five 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 2A : OVERVIEW OF FINANCIAL P OSITION This financial plan projects overall gas costs to increase from FY 2021 through FY 2026 at about 1.8% per year on average. Commodity prices have remained at near historic lows and there are not currently any indications that this will change, although weather and/or economic forces can shift this course rapidly. The cost to purchase Cap and Trade allowances, which offset the carbon created by burning natural gas, is expected to increase through 2030 as Palo Alto will continue to receive fewer annual free allowances and the auction price to purchase allowances increases annually by 5 percent plus inflation. On the operations side, there are some short term increases related to the cross-bore inspection program, and costs on average are projected to increase by about 2.6% annually. Capital improvement program (CIP) costs have also increased. While the COVID-19 pandemic has caused the economy in general to slow down, contractors have not reduced their prices as the national and regional focus on infrastructure improvement remains high, and the pool of skilled construction labor has not grown at the same pace. Costs are projected to increase by about 4.2% on average over the forecast horizon, when high and low budget years are averaged out. While CPAU generally has historically planned a new gas main replacement project every year, larger than expected bids have required resizing and redesign of some existing planned projects. The size, scope and complexity of the University Avenue Business District project, completed in 2019, resulted in no new CIP work being budgeted for FY 2020. Staff is currently budgeting for a new, larger main replacement project every other year, and this revised main replacement schedule will allow CPAU to reasonably meet its main replacement needs while addressing challenges in the current construction market and optimizing current staffing resources. However, if it is found that PVC pipe replacement should be started sooner, then the pace and size of main replacements may need to increase. Table 1 shows the Gas Utility expenses over the period of this financial plan. Table 1: Gas Utility Expenses for FY 2020 to FY 2026 (Thousand $’s) Expenses ($000) FY 2020 (act.) FY 2021 (est.) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Commodity costs 11,102 13,890 16,407 17,113 18,008 18,659 19,520 Operations 20,840 21,880 23,211 26,405 23,866 24,446 24,867 Capital Projects 3,342 9,283 4,674 7,717 4,261 11,297 4,150 TOTAL 35,285 45,053 44,292 51,235 46,136 54,403 48,537 GAS UTILITY FINANCIAL PLAN January 2021 6 | Page In order to move towards full cost recovery while minimizing rate impacts in light of pandemic- related economic challenges, the financial plan includes the rate trajectory shown in Table 2. Table 2: Projected Gas Rate Trajectory for FY 2021 to FY 2025 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current (FY 2022) Financial Plan 3% 5% 5% 5% 3% FY 2021 Financial Plan 5% 5% 5% 3% 3% FY 2020 Financial Plan 8% 6% 4% 1% 2% The Gas Utility maintains Rate Stabilization Reserves which can be used to smooth rate increases, and this Financial Plan proposes that these reserves will be exhausted by the end of FY 2021. The Gas Utility also has a CIP Reserve which is used to manage cash flow for capital projects, such as the staggered gas main replacement schedule, and fund capital contingencies such as unexpected spikes in CIP spending which do not merit separate bond financing. Table 3 shows the projected reserve transfers over the forecast period. GAS UTILITY FINANCIAL PLAN January 2021 7 | Page Table 3: Operations, Rate Stabilization and CIP Reserve Starting and Ending Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contribution To/(From) Reserves, and Reserve Guideline Levels for FY 2021 to FY 2026 ($000) SECTION 2B : SUMMARY OF PROPOSED ACTIONS Staff proposes the following actions for the Gas Utility in FY 2021: 1. Transfer unspent Cap and Trade related funds in the Operations Reserve to a new Cap and Trade Reserve ($4.542 million) 2. Transfer remaining funds in the Rate Stabilization Reserves to the Operations Reserve (currently $3.9 million) 3. Amend the Gas Utility Reserves Management Practices for the Cap and Trade Program Reserve, as shown in Appendix C, Section 6, and described above in Section 2A: Overview of Financial Position. FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Starting Reserve Balances 1 Operations Reserve 13,450 10,782 12,645 7,214 9,238 7,970 2 CIP Reserve 3,820 3,820 - - 1,000 - 3 Cap and Trade - 5,936 7,458 9,228 11,271 13,573 4 Rate Stabilization 8,419 - - - - - Revenues 5 Total Revenues 37,368 42,334 45,804 49,160 52,135 53,904 6 Cap and Trade 1,394 1,522 1,770 2,043 2,302 2,565 Transfers 7 Operations Reserve 3,877 3,820 - (1,000) 1,000 (2,000) 8 CIP Reserve - (3,820) - 1,000 (1,000) 2,000 9 Cap and Trade 4,542 10 Rate Stabilization (8,419) Expenses 11 Non-CIP Expenses (34,630) (39,618) (41,518) (41,875) (43,106) (43,584) 12 Planned CIP (9,283) (4,674) (9,717) (4,261) (11,297) (4,150) Ending Reserve Balances 1+5+7+11+12 Operations Reserve 10,782 12,645 7,214 9,238 7,970 12,141 2+8 CIP Reserve 3,820 - - 1,000 - 2,000 3+6+9 Cap and Trade 5,936 7,458 9,228 11,271 13,573 16,138 4+10 Rate Stabilization - - - - - - Operations Reserve Guidelines 13 Minimum 6,439 6,512 6,825 6,884 7,086 7,297 14 Maximum 12,879 13,025 13,650 13,767 14,172 14,593 CIP Reserve Guidelines 15 Minimum 1,770 1,725 1,920 1,775 1,989 1,856 16 Maximum 8,848 8,627 9,601 8,874 9,946 9,280 GAS UTILITY FINANCIAL PLAN January 2021 8 | Page Staff proposes the following actions for the Gas Utility in FY 2022: 1. Transfer up to $3.82 million from the Operations Reserve to the CIP Reserve to aid in funding of future CIP projects. 2. Increase distribution rates by 5% (an estimated 3% overall increase) for FY 2022, primarily reflecting increases to capital expenditures and increased operations costs. See Section 3B: Current and Proposed Rates for more details. SECTION 3: DETAIL OF FY 2022 RATE AND RESERVE PROPOSALS SECTION 3A : RATE DESIGN The Gas Utility’s rates are evaluated and implemented in compliance with cost of service requirements. The Gas Utility’s proposed rates are based on the methodology from the March 2019 Natural Gas Cost of Service and Rates Study. The City’s natural gas rates are based on the 2019 Natural Gas Cost of Service and Rates Study, updated with current and proposed operating costs. . With the onset of the COVID-19 pandemic, usage amongst customer classes has dropped to reflect people working and staying at home rather than going to the workplace. Similarly, businesses have been forced to operate at minimum staffing conditions or fully remote while the pandemic continues. City of Palo Alto staff have worked at reducing cost increases, and some capital project work has been moved out or restructured to keep costs from rising too much during this time. However, costs related to the Gas Utility’s resumption of main replacement projects and the cross-bore safety verification program are increasing. In order to move towards full cost recovery while minimizing rate impacts in light of pandemic-related economic challenges, staff recommends a distribution rate increase to all customer classes of 5%, which staff estimates will result in a 3% system average rate increase. If, after the pandemic, usage and/or spending looks to be moving in a different direction, staff will suggest a re-balancing of rates at that time. While staff is recommending that the distribution component of the rates be increased by 5%, distribution rates comprise about 70% of the overall rate, which consists of commodity (supply) and distribution components. Supply-related costs (the cost of the natural gas itself, gas transmission, and gas environmental charges) are a fluid component of the Gas Utility’s expenses. It not possible to precisely predict commodity rates, which make up approximately 30% of overall retail gas rates. Market prices are monitored monthly and automatically incorporated into monthly supply rate adjustments, which are passed directly to customers as a line item on their utility bills. Because it is not possible to exactly predict what supply rates will be during the planning horizon, the overall rate increases (commodity plus distribution) referenced in this report assume that the commodity portion of the overall rate remains unchanged. The net effect is a proposed 3% overall rate increase. Table 4 below shows both the proposed increase in distribution rates (about 5%), and the net impact on rates including commodity costs (about 3% overall, as distribution is about 2/3 of total rate revenue): GAS UTILITY FINANCIAL PLAN January 2021 9 | Page Table 4: Cost of Service (COSA) Distribution Revenue Requirement by Customer Class Cost of Service Analysis FY 2022 Rate Increase needed for Distribution Charges Assumed Commodity Rate Changes Net Rate Increase for Combined Commodity and Distribution Charges G1 – Residential 5% 0% 3% G2 - Small Commercial 5% 0% 3% G3 - Large Commercial 5% 0% 3% TOTAL 5% 0% 3% Rate impacts of these changes are outlined in Section 3B: Current and Proposed Rates. SECTION 3B : CURRENT AND PROPOSED RATES Gas rates have two drivers: 1) Commodity costs – these are costs related to the purchase of gas supply, transmission costs to bring the gas to Palo Alto’s meters, and environmental costs, such as the purchase of cap and trade allowances for gas burned and carbon neutral offsets; and 2) Distribution costs. On July 1, 2012 CPAU restructured its rates so that the commodity component of the rates varied monthly to match changes in gas market prices.1 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 program.2 This component changes depending on the cost of allowances and gas demand. In October 2016, the Council adopted a resolution changing the Local Transportation rate (which had been collapsed into the Distribution rate in 2015 to streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to Wholesale/Resale Customers (G-WSL) charge to Palo Alto.3 This went into effect November 1, 2016. In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a carbon neutral gas portfolio by FY 2018.4 Costs associated with the carbon neutral gas plan are passed through directly to customers as well, although the rate impact is not to exceed $0.10 per therm. At this point, all gas supply, transmission, and environmental costs are passed through to customers as prices change. Three years’ worth of history of these commodity rate components can be found on Palo Alto’s website.5 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 schedule for the Compressed Natural Gas station (G-10). To recover distribution costs, all customers pay a monthly service charge, which funds meter reading, billing, and other customer service costs, as well as a portion of operations and maintenance costs. All customers are also assessed a distribution charge based 1 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 2 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537 3 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165 4 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882 5 Monthly Gas Commodity & Volumetric Rates http://www.cityofpaloalto.org/civicax/filebank/documents/30399 GAS UTILITY FINANCIAL PLAN January 2021 10 | Page on 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. Fixed charges include both customer service and meter reading costs as well as a portion of distribution system costs. Table 5 shows the current monthly service charges for all rate schedules. Table 6 shows the consumption charges related to distribution, and the increase in CIP spending has an effect here as well. As mentioned earlier, commodity charges change monthly, and transportation charges are tied to the PG&E G-WSL rate schedule. Some recent commodity price history is discussed in Section 6A: Gas Purchase Costs. . Table 5: Current and Proposed Monthly Service Charges Rate Schedule Monthly Service Charge ($/month) Change Current (as of 7/1/20) Proposed for FY 2022 ($) (%) G-1 (Residential) $10.37 $10.89 $0.52 5.0% G-2 (Small Commercial) 96.05 100.85 4.80 5.0% G-3 (Large Commercial) 439.46 461.43 21.97 5.0% G-10 (CNG) 64.96 68.21 3.25 5.0% Table 6: Current and Proposed Gas Distribution Charges Change Current (as of 7/1/19) Proposed for FY 2021 ($) (%) G-1 (Residential) Tier 1 Rates $0.5038 $ 0.5290 $0.0252 5.0% Tier 2 Rates 1.2882 1.3526 0.0644 5.0% G-2 (Residential Master-Metered and Small Commercial) Uniform Rate 0.6617 0.6948 0.0331 5.0% G-3 (Large Commercial) Uniform Rate 0.6551 0.6879 0.0328 5.0% G-10 (Compressed Natural Gas) Uniform Rate 0.0108 0.0113 0.0005 5.0% GAS UTILITY FINANCIAL PLAN January 2021 11 | Page SECTION 3C : BILL IMPACT OF PROPOSED RATE CHANGES Table 7 shows the impact of the proposed July 1, 2021 rate changes on the median residential bill. The average increase for the residential class is roughly 3 percent on average based on last year’s commodity prices. As the price of commodities changes monthly, the actual increase may be higher or lower than the 3% average. Table 4 shows a representative Winter period (November thru March) and Summer period (April through October) bill comparison: Table 7: Impact of Proposed Gas Rate Changes on Residential Bills Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change $/mo. % Winter (Using November 2020 commodity prices) 30 $ 41.88 $ 43.15 $ 1.27 3.0% 54 (median) 67.09 68.97 1.88 2.8% 80 110.08 113.40 3.32 3.0% 150 238.51 246.34 7.83 3.3% Summer (Using October 2020 commodity prices) 10 $ 20.85 $ 21.62 $ 0.77 3.7% 18 (median) 29.23 30.20 0.97 3.3% 30 49.13 50.79 1.66 3.4% 45 76.61 79.24 2.63 3.4% Table 8 shows the impact of the proposed July 1, 2021 rate changes on various representative commercial customer bills. The overall increases for the G-2 and G-3 classes are projected to be about 3% on an annual basis. Table 8: Impact of Proposed Gas Rate Changes on Commercial Bills (Using November 2020 commodity prices) Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change % 500 685 706 3.1% 5,000 5,986 6,156 2.8% 10,000 11,875 12,211 2.8% 50,000 59,005 60,665 2.8% SECTION 3D: PROPOSED RESERVE TRANSFERS This Financial Plan proposes to transfer any remaining funds (currently $8.4 million) from the Rate Stabilization Reserve into the Operations Reserve, establishes a Cap and Trade Program GAS UTILITY FINANCIAL PLAN January 2021 12 | Page Reserve, and transfers collected but unspent Cap and Trade revenues to the Cap and Trade Program Reserve ($4.542 million) in FY 2021. These funds will be used to mitigate rate increases, clearly reflect unspent Cap and Trade revenues, and otherwise bring the Rate Stabilization reserves to zero. Section 7 of the Gas Utility Reserves Management Practices states that 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. Once the funds are withdrawn under this plan, they will help keep rates lower by funding operations and supply costs. CIP Reserve There is $3.8 million currently in the CIP Reserve. These funds can be used to cover additional, one-time capital costs, and with the current plan to stagger main replacement projects every other year, they can also be used to hold funds collected from rate revenues that will fund CIP projects in a future year. As shown in Figure 6 below, in a year with no capital project budgeted, rate revenues may exceed that year’s capital expenses, but conversely, in years with a main replacement project, rates may not cover total capital costs. As first described in the FY 2021 Gas Utility Financial Plan, these annual changes are managed by transferring funds from the Operations Reserve to the CIP Reserve in non-main replacement years and using those funds for capital expenses in years with main replacements and other capital program expenses. The net effect is a more evenly funded Operations Reserve and a CIP reserve that better reflects available funds for projects. The proposed transfer for FY 2022 is an amount up to $3.8 million, although the amount may be less if Operations reserve is higher than forecast. If the ending Operations Reserve balance at the end of FY 2021 allows for the transfer to take place, then next year’s Financial Plan will advocate for an annual funding for CIP based on staff’s estimate of annual CIP work for the next 48 months, currently estimated at about $7.5 million. The Gas CIP Reserve will need to have enough funds to absorb a high-year ($12 to $14 million) CIP budget after receiving the annual funding while still remaining above the minimum guideline to start. Using the CIP Reserve this way will avoid the annual fluctuations of actual CIP costs and revenues from the Operations reserve (and therefore avoid rate spikes required to fund CIP cost increases).6 If projects do not get completed within the budgeted year and the CIP reserve balance grows beyond the maximum guideline, staff may request lowering the amount of annual 6 In several municipalities (as well as CPA’s General Fund), capital projects are budged for in this way. The utility transfers a certain amount of approved annual funding to the CIP fund to cover average projected costs and maintain contingency reserves as approved by Council. The day to day project-related expenses and revenues are still accounted for in their respective cost centers, but surpluses or deficits flow into and out of the CIP reserve rather than Operations. GAS UTILITY FINANCIAL PLAN January 2021 13 | Page funding until projects are rescheduled. In contrast, if project costs come in higher than expected, the Operations and CIP fund balances can cover increased costs. In the short term, until an annual funding and/or initial funding of the CIP reserve can occur, the current plan shows the CIP reserve balance falling below the minimum reserve guideline every other year with the cyclical main replacement projects. Cap and Trade Program Reserve The Global Warming Solutions Act of 2006, also known as Assembly Bill (AB) 32, authorized the California Air Resources Board (CARB) to develop regulations to lower the state’s greenhouse gas (GHG) emissions to 1990 levels by 2020. CARB developed a cap-and-trade program as one of the strategies to achieve the 2020 goal. Under the cap-and-trade program, an overall limit on GHG emissions from capped sectors is established and facilities subject to the cap are able to trade permits (allowances) to emit GHGs. To do this, entities with emissions are required to hold enough allowances (an allowance being equivalent to one metric ton of greenhouse gas, or CO2e) to cover its emitted output in a given year, also called its ‘compliance obligation.’ In addition, certain entities and public power agencies, such as Palo Alto, have been distributed free allowances to reduce the rate shock to customers from the purchase of required allowances. Revenues from the auction sale of gas utility allowances must be used exclusively for the benefit of the ratepayers in that utility. California Code of Regulations (CCR Title 17, section 95893) details how entities must use those funds, but in general, these can be for 1) the funding of certain energy efficiency rebates, retrofits, and demand reduction programs, 3) funding for programs with demonstrated GHG reductions, 4) non-volumetric return to ratepayers, either on or off bill, and 5) certain administrative, outreach and educational costs related to items 1-4 above. The City Council has also adopted a policy on the use of allowance proceeds (Resolution 9487), generally mirroring the regulations and requiring additional Council approval for rebates. Per the current regulations, the utility must either spend or rebate the funds received in any given year within 10 years (for example, funds received in 2020 must be spent by 2030, etc.). To date the unspent Cap and Trade revenues have been tracked internally and placed in the Rate Stabilization Reserves. Staff is seeking to call these funds out in a separate reserve for ease ofaccounting and clarity. The impact of these proposed transfers on reserves levels can be seen in Table 3 above and in Appendix A: Gas Utility Financial Forecast Detail. SECTION 4: UTILITY OV ERVIEW 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. GAS UTILITY FINANCIAL PLAN January 2021 14 | Page SECTION 4A: 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 was comprised of 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 gasification 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 CPUC) 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 polyethylene (PE) mains over the course of the following 36 years.7 As of 2020, the Gas Utility has replaced all but .11 miles of ABS gas mains, which consists of mainly short sections of pipelines in various locations throughout the City. Current pipeline replacement projects are targeting the replacing of all ABS, Tenite and K40 gas services, to be completed in Summer 2020, and PVC pipe during larger Capital Improvement Projects. The Gas Utility has identified approximately 30,000 linear feet of PVC gas main and over 300 natural gas services for replacement in FY21. 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.8 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 7 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990 8 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 GAS UTILITY FINANCIAL PLAN January 2021 15 | Page 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,”9 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 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. 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 program.10 As of November 1, 2016, the Council adopted a resolution changing the Local Transportation rate (which had been collapsed into the Distribution rate in 2015 to streamline bill presentation), to be a pass-through of PG&E’s Gas Transportation Rate to Wholesale/Resale Customers (G-WSL) charge to Palo Alto.11 In December 2016, Council approved a carbon neutral gas plan, with a goal of achieving a carbon neutral gas portfolio by FY 2018.12 SECTION 4B : CUSTOMER BASE CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas customers in Palo Alto. Close to 23,800 customers are connected to the natural gas system, approximately 21,500 (90%) of which are residential and 2,300 (10%) of which are non- residential. In a normal year, residential customers consume about 10 to 11 million therms of gas per year, roughly 40% of the gas sold, while non-residential customers consume 60% (about 17 to 18 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 9 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 10 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537 11 Staff Report 7260 10/17/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54165 12 Staff Report 7533 12/05/2016 http://www.cityofpaloalto.org/civicax/filebank/documents/54882 GAS UTILITY FINANCIAL PLAN January 2021 16 | Page cooking, clothes drying, and heating pools and spas.13 Non-residential customers use gas for space and water heating (73% of gas consumed), cooking (20%), and industrial processes (6%).14 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 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 (bidweek) prices. In a similar fashion, the cost for local transportation is tied to PG&E’s G-WSL rate schedule, and varies when and if PG&E changes its rate schedule. The cost of purchased gas and PG&E local transportation service usually account for roughly one third of the utility’s expenditures. SECTION 4C : DISTRIBUTION SYSTEM 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 close to 23,800 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 normally accounts for around 15 to 20% on average 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, $1 million is estimated per year for the cross-bore program through FY 2022. 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. 13 http://energyalmanac.ca.gov/naturalgas/overview.html 14 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 January 2021 17 | Page SECTION 4D: C OST S TRUCTURE AND R EVENUE S OURCES As shown in Figure 1, the Gas Utility receives about 90% 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 2020, gas purchase costs accounted for about a third of the Gas Utility’s costs. This percentage can vary widely from year to year, as this cost is based upon market purchases, and now also includes costs related to cap and trade. Operational costs in FY 2020 represented 65% of expenses and capital investment was responsible for the remaining 8%. CIP is normally about 15 to 20% of expenses, but this may be lower in times when spending for new projects is deferred, as happened in FY 2017. SECTION 4E : RESERVES STRUCTURE CPAU maintains six reserves for its Gas Utility to manage various types of contingencies and track program spending. The summary below describes each of these briefly. 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 Re-appropriations: A reserve for funds dedicated to projects re-appropriated by the City Council, nearly all of which are capital projects. Most City funds, including the General Fund, have a Re-appropriations Reserve. • Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate funds for future expenditure on CIP projects. This CIP can also act as a contingency reserve Figure 2: Cost Structure (FY 2020) 65% 27% 8% Operations Gas Purchases Capital Figure 1: Revenue Structure (FY 2020) 89% 11% Sales of Gas Other Revenue GAS UTILITY FINANCIAL PLAN January 2021 18 | Page 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. • Cap and Trade Reserve: This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the gas utility, under the State’s Cap and Trade Program. SECTION 4F: COMPETITIVENESS Table 9 presents winter and summer residential bills for Palo Alto and PG&E at several usage levels for commodity rates in effect as of July 2020 (to illustrate a summer month bill) and December 2020 (to illustrate a winter month bill). The annual gas bill for the median residential customer for calendar year 2020 was $523.59, about 12% lower than the annual bill for a PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased substantially to collect for needed system improvements for pipeline safety and maintenance. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which includes the surrounding communities. Table 9: Residential Monthly Natural Gas Bill Comparison ($/month) Season Usage (therms) Palo Alto PG&E Zone X % Difference Winter (December 2020) 30 $ 40.97 49.66 -17.5% (Median) 54 65.45 92.48 -29.2% 80 106.09 149.00 -28.8% 150 232.40 301.19 -22.8% Summer (July 2020) 10 $ 19.31 14.07 37.3% (Median) 18 26.46 26.77 -1.2% 30 44.51 49.86 -10.7% 45 69.69 78.72 -11.5% Table 10 shows the monthly gas bills for commercial customers for various usage levels for rates in effect as of December 2020. Bills for CPAU customers at the usage levels shown can vary between 12% lower to 15% higher for 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 GAS UTILITY FINANCIAL PLAN January 2021 19 | Page attributable to PG&E’s higher distribution rates as the commodity rates for CPAU and PG&E are very similar, both being based on spot market gas prices. Table 10: Commercial Monthly Average Gas Bill Comparison (for Rates in Effect December 2019) Usage (therms/mo) Gas Bill ($/month) % Difference Palo Alto PG&E 500 685 718 (5%) 5,000 5,986 6,831 (12%) 10,000 11,875 12,045 (1%) 50,000 59,005 51,419 15% SECTION 4G : 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. Figure 3 shows the actual commodity prices charged. Prior to December 2018, commodity prices had generally fluctuated in a fairly narrow band, averaging around $0.32/therm. However, in December 2018, a variety of factors combined that led to a one time market spike: Regional temperatures were cooler than normal, but in addition, gas supplies stored in underground facilities were lower than normal, as well as constrained due to problems with the Aliso Canyon facility in southern California. There were also pipeline constraints at both the northern and southern California borders. While there was not an actual constriction on supply, the confluence of all these factors drove up the bidweek prices for all California delivery points. Once it was seen that these factors were not causing gas supply shortages, prices returned to levels more commonly seen. There has continued to be a bit more volatility in the market of late, and the trend of prices appears to be slightly upward over time. GAS UTILITY FINANCIAL PLAN January 2021 20 | Page Figure 3: Gas Commodity Rates from July 2012 through January 2021 SECTION 5: UTILITY F INANCIAL PROJECTIONS SECTION 5A : LOAD FO 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 significant 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 2014 and 2015, unusually warm winters, as well as ongoing drought, caused gas usage to tumble to historic lows. In FY 2017 and FY 2018, as the drought had eased, gas usage increased again, but appeared to have stabilized. The COVID pandemic of 2020 has resulted in gas usage decreasing again, mainly in the commercial sectors as a result of many businesses operating staff remotely. The impact to FY 2020 was a drop of about 2.6% from projections, and projections for FY 2021 assumed similar losses of 2 to 4%. However, monthly consumption during the early part of FY 2021 showed loses of between 6 to 10%, indicating that gas usage was being impacted much more than initially thought. GAS UTILITY FINANCIAL PLAN January 2021 21 | Page Figure 4: Historic Gas Consumption The ongoing nature of the pandemic, as well as usage declines similar to what has been seen in the electric utility, leads to questions of how long the trend of reduced consumption in gas will last. Staff worked with the NCPA to incorporate UCLA’s Anderson School GDP forecast into its electric load forecast for Palo Alto, which estimates the economic trend impacts to last through December 2020. The same recovery pattern was used in Figure 5 below to forecast various possible levels of gas usage recovery. As seen with prior economic and drought gas usage declines in the past, it is likely that consumption will not come back to pre- conservation/pandemic levels, but will likely stabilize closer to the longer-run decline in gas usage seen over the years. Further changes, such as the voluntary replacement of gas appliances with electric appliances, building electrification of new construction as mandated by the 2019 Reach Code, and customer behavior are also expected to lower long run usage, and this forecast will be revised accordingly as more customers adopt these measures.15 Based on billing data through December 2020, which has shown some recovery with the return of winter heating, the monthly usage is matching closer to the ‘Medium Recovery’ (about a 6 to 7% usage decline) line shown in Figure 5, and this is the scenario utilized for the proposed rate projections. The ‘Deep Recovery’ (about a 10% usage decline) line would result in roughly $1 15 The City’s Sustainability and Climate Action Plan (S/CAP) is currently being updated. As building electrification goals in the S/CAP are updated, they will be modeled in this load forecast. GAS UTILITY FINANCIAL PLAN January 2021 22 | Page million in additional lost revenues, and may require corresponding expense cuts if future sales do not recover in a faster fashion. It is too early in the winter heating season to tell what the trend will continue to be. However, the faster that gas consumption falls, that will put upward pressure on rates, as a generally increasing cost to operate and distribute gas will be spread across fewer units of sale. Figure 5: Forecast Gas Consumption S ECTION 5A : FY 2016 TO FY 2020 COST AND REVENUE TRENDS Figure 6 and Appendix A: Gas Utility Financial Forecast Detail show how costs have changed during the last five years as well as how staff project costs to change over the next decade. While the gas utility strives to maintain a steady rate of funding for main replacement over time, this funding pattern was disrupted from FY 2015 to FY 2020. In FY 2015, no funding for gas main replacement was budgeted due to the fact that staff was completing a prior major gas main replacement project, the largest in utility history, which completed replacement of most of the ABS gas mains in Palo Alto. The next main replacement to be budgeted involved replacements of gas mains on University Avenue, a project that evolved into the Upgrade Downtown project involving a coordinated replacement of several different types of infrastructure to avoid multiple disruptions to the business district. This multi-year planning effort that did not allow for design of other new projects, and the hiatus in starting a new main replacement project allowed the Gas Utility to temporarily keep rates lower. FY 2021 marked the return to routine funding for main replacement for the gas utility. However, due to the pattern of funding from FY 2015 to FY 2020, rates are currently lower than they will need to be to fund future capital replacement while also funding operations. This Financial Plan includes the rate increases needed to fund regular main replacement going forward. Revenues have generally matched expenses in most years and were slightly higher than expenses in FY’s 2016 and 2017. The absence of new budget funding for main replacement projects for several years, as well as the availability of relatively large reserves, forestalled the need for rate increases until FY 2019. GAS UTILITY FINANCIAL PLAN January 2021 23 | Page As shown in Figure 6, the last adjustment to gas distribution rates was in July 2020 when CPAU increased distribution rates, resulting in a 2% increase to the total system average gas rate (supply rates plus distribution rates). The revenue (and commodity cost) increase in FY 2019 was the result of a relatively cooler winter leading to higher usage, but also a spike in commodity prices, as can be seen on Figure 3 in Section 4G, above. Figure 6 assumes no change in gas supply costs over the forecast period to illustrate the impact of proposed distribution rate changes on the overall customer bill. In reality, gas supply costs are uncertain and are passed through to customers as they change month to month. Figure 6: Gas Utility Expenses, Revenues, and Rate Changes: Actual Costs through FY 2020 and Projections through FY 2026 SECTION 5B : FY 2020 RESULTS With the onset of the COVID epidemic in March/April 2020, sales in FY 2020 were about 1.1 million lower than were forecast in the FY 2021 financial plan. Sales revenues were lower by about $1.7 million, but other sources of funds were higher by $1.1 million. On the expense side, a modelling error for purchase costs, which should have all been shown as pass-through, instead had some values only showing a partial collection through rates. This resulted in the purchases forecast being lower by $3.3 million than it should have. This did not directly affect retail rate GAS UTILITY FINANCIAL PLAN January 2021 24 | Page setting since the modeling error was in the supply rates, which are passed through based on monthly market prices, but it did affect staff’s projection of reserve levels in the FY 2020 Financial Plan. This modelling error was corrected in the FY 2021 Financial Plan. Operational expenses came in about $456,000 below the expected budget. Total FY 2020 expenses were $39.3 million compared to projections of $35.3 million in the final FY 2021 Financial Plan. Table 11 summarizes the variances from forecast. Table 11: FY 2020, Actual Results vs. FY 2021 Financial Plan Forecast ($000) Net Cost/(Benefit) Type of change Lower Sales revenues than forecasted. 1,728 Revenue decrease Operations cost savings (456) Cost savings Increased interest income and other non- sales revenues (1,124) Revenue increase Lower purchase costs due to lower sales 16 (3,260) Cost increase Net Cost / (Benefit) of Variances (4,319) SECTION 5C : FY 2021 PROJECTIONS Current projections indicate that sales revenues will be slightly lower than last year’s forecast. This is a combination of both lower sales due to COVID impacts, but offset by higher projected commodity costs (estimated at $765,000). Other revenues and transfers are projected to be higher, making up for the loss. Operations costs are tentatively estimated to be lower by about $1.1 million based on updated projections using actual expenses from FY 2020, which were lower than previously forecast. The variances nearly offset, making the ending proposed reserve changes very similar to last year’s projection. Table 12 summarizes the current and projected variances from the FY 2021 Financial Plan. Table 12: FY 2021 Projected Results vs. Current Financial Plan Forecast ($000) Net Cost/ (Benefit) Type of change Sales decrease due to COVID impacts 392 Revenue decrease Operations cost savings (1,123) Cost decrease Increased purchase cost estimates 765 Cost increase Other revenues higher than forecast (811) Revenue increase Net Cost / (Benefit) of Variances (61) SECTION 5D : FY 2022-FY 2026 PROJECTIONS Figure 6 above shows staff projections that overall costs for the Gas Utility are increasing in FY 2021. This is largely in part due to a modified CIP schedule starting in FY 2020. For FY 2020 through 2026, staff anticipates annual capital expenditures will fluctuate due to planning for larger main replacement construction projects every other year instead of smaller projects 16 Note: Typically lower sales result in purchase cost decreases that are roughly the same or smaller than the sales revenue decreases. This was not the case in FY 2020 due to the modeling error in the FY 2020 Financial Plan described above. GAS UTILITY FINANCIAL PLAN January 2021 25 | Page annually. This revised main replacement schedule will allow CPAU to meet its main replacement needs while addressing challenges in the current construction market and optimizing current staffing resources. Averaging the cost of CIP over these two-year cycles, costs are expected to increase by around 4.2% on average annually through FY 2026. In Operations, there is a short run addition of $1 million per year in FY 2022 and FY 2023 for cross-bore inspections (this expense is projected to continue for at least two years, but could be longer depending on what system investigations show as well as work restrictions due to COVID). General inflationary increases are expected of around 2 to 3% per year. Salaries and benefits expenses are projected to rise at 3 to 6% per year, per the assumptions used in the City’s Long Range Financial Plan projections. Construction costs have not appeared to decrease during the COVID-related recession, as they did during the last economic downturn. The next new main replacement project after the University Avenue project started in FY 2021, and ongoing main replacement is expected to be more expensive. Gas commodity costs are the most variable component. Factoring in the rising costs for cap and trade allowances (including recent legislation providing fewer free allowances and therefore higher purchase needs), carbon offset products and rising transmission expenses, costs could increase by around 8% per year by 2026. These costs are expected to taper off after that point, but these costs are also directly correlated to gas sales. Given that COVID has decreased sales to record low levels, a resumption to ‘normal’ usage will incur correspondingly higher costs. Since these costs are pass-through charges to customers, the impact to reserves of these costs being higher or lower than expected is minimal. As shown in Figure 7, this financial plan projects the Rate Stabilization Reserves to be depleted by FY 2021. In addition, in years where revenues are higher than expenses due to those being CIP planning years, funds will be moved into the CIP reserve to help counter the following year’s higher CIP related costs. GAS UTILITY FINANCIAL PLAN January 2021 26 | Page Figure 7: Gas Utility Reserves Actual Reserve Levels for FY 2020 and Projections through FY 2026 Staff is evaluating when to best implement a fixed funding amount (currently estimated at $8.6 million, derived by calculating the approximate average annual CIP budget for FY 2021 through FY 2025) that will be provided from the Operations Reserve to the CIP Reserve to fund capital improvements. This approach will provide stability to the Operations Reserve by providing for a steady funding stream for CIP work and by reflecting fluctuations due to CIP such as project delays or accelerations in the CIP Reserve; ultimately, this stability should provide more stable customer rates. The use of the CIP Reserve in this way will isolate fluctuations due to CIP delays or accelerations and allow those to be viewed together in the CIP Reserve. Conversely, other trends or factors affecting the Operations Reserve will be easier to identify and communicate via that reserve. Without this change, both CIP costs and revenues flows solely through the Operations Reserve. However, in order to keep rate impacts lower to customers in light of the COVID-19 pandemic, staff is not anticipating being able to implement fixed funding at this time, and possibly not within the 5-year planning horizon. Staff will evaluate the applicability of this plan as ending reserve balances become available. In the short run, this plan shows that the CIP reserve will fall below the minimum reserve guideline until annual funding and/or another transfer of funds to the CIP GAS UTILITY FINANCIAL PLAN January 2021 27 | Page reserve can be done. Figure 8 below shows the current estimate of CIP reserve fund balances before an annual funding amount is applied. Figure 8: Gas CIP Reserves Reserve Level Projections through FY 2026 SECTION 5E : RISK ASSESSMENT AND RESERVES ADEQUACY This Financial Plan projects the Gas Utility’s primary contingency reserve, the Operations Reserve, to be within guideline levels throughout the forecast period. Staff is accomplishing this by reducing the size of projected CIP projects in FY 2021 and FY 2023. . Figure 9 shows the Operations Reserve within the guideline levels. GAS UTILITY FINANCIAL PLAN January 2021 28 | Page Figure 9: Operations Reserve Adequacy Forecasted Operations Reserve levels also exceed the short-term risk assessment for the Utility. Table 13 summarizes the risk assessment calculation for the Gas Utility through FY 2026. 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 13: Gas Risk Assessment ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Total non-commodity revenue $22,900 $24,325 $26,948 $29,369 $31,505 $32,559 Max. revenue variance, previous ten years 16% 16% 16% 16% 16% 16% Risk of revenue loss $3,672 $3,901 $4,321 $4,710 $5,052 $5,221 CIP Budget $8,200 $3,550 $8,550 $3,050 $10,050 $3,050 CIP Contingency @10% $820 $355 $855 $305 $1,005 $305 Total Risk Assessment value $4,492 $4,256 $5,176 $5,015 $6,057 $5,526 SECTION 5F : 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 GAS UTILITY FINANCIAL PLAN January 2021 29 | Page their environmental impacts. On the demand side, a continued shift from coal to natural gas for electricity generation, an expansion of export capabilities, or an increase in manufacturing in the U.S. might drive up natural gas prices, but other factors, such as generally more mild winters or an increased drive towards electrification, 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 of the Gas Utility by continuing its current strategy of passing these costs directly to its customers via month-varying rate adjustment mechanisms. The City pursues a policy of purchasing offsets to make gas usage in Palo Alto carbon neutral. The cost is not to exceed $0.10/therm. Future CIP investment needs for the Gas Utility may be lower than in the past, although costs per foot for main replacement have been increasing 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 continuing to study and develop its future main replacements priorities and strategy. Long-term state or local climate goals will 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. 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. However, to achieve the recently adopted Sustainability and Climate Action Plan (S/CAP) goal of an 80% reduction in carbon emissions by 2030, or the State’s adopted goal of an 80% reduction in emissions by 2050, extensive electrification of gas-using appliances is necessary. 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. 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.”17 Staff has already begun to evaluate how to manage potential impacts of these trends over the next few years. SECTION 5G: ALTERNATIVE GAS INCREASE PLANS Alternative Proposal: No increases in FY 2022 In the interest of providing options to help the community keep its utility bills low during the economic crisis created by the COVID-19 pandemic, the Utilities Department is showing an alternative rate plan involving no rate increase in FY 2022 and no more than 5% rate increases in the subsequent financial plan years. In order to do this, staff looked at a 10 year forecast period 17 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 January 2021 30 | Page rather than 5 years so as to better maintain the City’s priorities for its utilities (safety, reliability, cost-effectiveness, and sustainability) over the forecast period. Table 14: Projected Gas Rate Trajectory for FY 2022 to FY 2030 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 Current Financial Plan 0% 5% 5% 5% 5% 2% 1% 1% 1% In order to have this rate increase trajectory, however, the Gas Utility would require approximately $4.7 million in expense reductions to keep Operations reserves above minimum guideline levels. This has been estimated as $2.2 million in FY 2023 and $2.5 million in FY 2025. Without these cuts, the Operations Reserve trajectory would go below both the minimum and risk assessment guidelines, as shown in Figure 10: Figure 10: Operations Reserve with No Expense Reductions With the reductions, the Operations Reserve is projected to stay at or near minimum though FY 2025 and would not reach target levels until FY 2026: GAS UTILITY FINANCIAL PLAN January 2021 31 | Page Figure 11: Operations Reserve with Expense Reductions To make reductions this large, temporarily bond financing capital expenditures could be a reasonable option. But given the City’s ambitious building electrification goals, long-term bond financing may not be prudent. This means that staff may need to temporarily make significant reductions in capital investment for this utility. Examples of the types of actions that might need to be taken by the Gas Utility include: • Ending the City’s Carbon Neutral Gas carbon offset program (~$1 million to $1.5 million per year, depending on market prices) • Temporarily reducing utility efforts in energy efficiency in the sectors with longer payback periods for efficiency investments (residential and small and medium business customers). (Exact amount subject to internal review of various programs to review payback periods. Total annual gas efficiency spending is approximately $600,000 per year.) • Postponing or eliminating cross-bore inspections • Postpone installation of advanced metering infrastructure and gas meter replacement (~$3 million in FY 2022) • Cutting back on capital investment by postponing or reducing project scope of work of gas main PVC pipe replacement (up to $10 million) • The impacts of implementing all of the above cost reductions would impede sustainability efforts, leave the City at some level of risk from cross-bores, delay customer availability of hourly usage data for several years, and slow down the rate of replacement of PVC gas mains, which have glued joints that are at higher risk of leakage during an earthquake. To offset the potential safety impact of these cost reductions, Utilities would increase the frequency of citywide gas surveying (mobile and walking) for gas leaks ($100,000). GAS UTILITY FINANCIAL PLAN January 2021 32 | Page SECTION 6: D ETAILS AND A SSUMPTIONS SECTION 6A : 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 Citygate, even including the costs of transmission from Malin to Citygate. The Gas Utility purchases gas 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 slowly declining over time. In FY 2019, however, lower levels of natural gas in storage , along with colder than normal weather and pipeline constraints on both the northern and southern borders of California has created some short term price spikes, as shown in Figure 12. Figure 12: Gas Market Prices at PG&E Citygate On September 15, 2014, Council adopted Resolution #9451 authorizing the City’s participation in a natural gas purchase from Municipal Gas Acquisition and Supply Corporation (MuniGas) for the City’s entire retail gas load for a period of at least 10 years. The MuniGas transaction includes a mechanism for municipal utilities to utilize their tax-exempt status to achieve a discount on the market price of gas. As of November 1, 2018, gas began flowing under this program, reducing the City’s gas commodity cost by about $1 million per year and saving gas customers approximately $0.03 per therm on the commodity portion of their bills. Gas commodity costs are expected to increase slowly but steadily over the next several years. Figure 13a 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. GAS UTILITY FINANCIAL PLAN January 2021 33 | Page Figure 13a: Wholesale Gas Price Projections Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary adder to PG&E’s local transportation rate,18 but in December 2014 PG&E applied to the CPUC to more than double local transportation costs. The application was not settled until late 2016. As these charges are dictated by PG&E and are outside of Palo Alto’s control, staff proposed making these costs pass-through charge, similar to the commodity charge, and this became effective in November 2016. Figure 13b shows some historical as well as projected transmission cost projections: 18 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 January 2021 34 | Page Figure 13b: Gas Transportation Cost Projections For Cap and Trade compliance costs, the gas utility has been regulated under California’s greenhouse house (GHG) regulations since January 2015 with a GHG emissions cap that declines over time. The gas utility receives carbon allowances equal to the emissions allowed under the cap and is required to auction off a portion (50% in 2021, increasing by 5% annually) of the allowances through the state Cap and Trade Program. To meet its annual GHG compliance obligation, the gas utility must purchase allowances based on actual gas load. The auction price to either purchase or sell allowances also increases annually by 5% plus inflation. Given the rate of increased allowance purchases and the increasing market prices, these costs are anticipated to increase from $1.5 million in FY 2022 to $5.6 million in FY 2030, about an 18% increase per year on average. The City also has a Carbon Neutral Natural Gas plan (Staff Report 7441 19), which go towards buying offsets for natural gas. These high-quality carbon offsets support projects that reduce the amount of GHGs in the atmosphere, such as planting trees or capturing methane from dairy farms. The climate impact of our natural gas use is thus carbon neutral. Purchasing carbon offsets is a good first step towards reducing carbon in the atmosphere, but our longer-term goal is to reduce our use of natural gas by maximizing efficiency and switching to high-efficiency electric appliances where possible. The costs for these offsets are projected to increase from $2.2 million in FY 2022 to $5.1 million in FY 2030, or about an 11% increase per year on average. 19 https://www.cityofpaloalto.org/civicax/filebank/documents/54588 GAS UTILITY FINANCIAL PLAN January 2021 35 | Page SECTION 6B : OPERATIONS Operations costs include the Customer Service, Demand Side Management, Operations and Maintenance (including Engineering), Resource Management, and Administration categories in Figure 11, 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 generally 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 2022 to FY 2023 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 included roughly $3 million in additional funding between FY 2019 and FY 2022 for this program, but the program will likely require additional funding in future years to complete. GAS UTILITY FINANCIAL PLAN January 2021 36 | Page Figure 14: Historical and Projected Operational Costs SECTION 6C : 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 ranked to have the highest threat scores within the system. • 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, gas pipeline maintenance and emergency equipment. • One-time Projects, which represents occasional large projects that do not fall into any other category. Table 15 shows the current status of these project categories and future projected spending. GAS UTILITY FINANCIAL PLAN January 2021 37 | Page Table 15: Budgeted Gas CIP Spending ($000) The Gas Main Replacement (GMR) Program has completed a major milestone with the replacement of gas mains made from Acrylonitrile-Butadiene-Styrene (ABS) plastic. There is 0.1 miles of remaining ABS in the system, scattered throughout the City in very small sections. With the replacement of all ABS mains with Polyethylene (PE) plastic completed, the material most at risk for failure is the remaining Polyvinyl chloride (PVC) plastic and steel (wrapped, with cathodic protection). The next focus of the GMR program will be the replacement of all PVC mains with PE mains. CPAU has been updating the Gas System Master Plan to determine which sections of pipeline to prioritize and assist in determining the pace of main replacement. With the current economic restrictions, replacement of PVC mains has been reduced to approximately three to four miles per year, or 1.9% of the system. The current budget for the gas main replacement program takes into account the rise in construction costs. Several factors are contributing to the increase in construction costs in the Bay Area, such as a greater focus on infrastructure improvement by many municipal agencies, and the higher demand for utility contractors within these fields. CPAU has seen the replacement cost per linear foot steadily increase, even in the current economic conditions brought about by the COVID epidemic. The Gas Utility posted the most recent project for competitive bid (the Gas Main Replacement 23 Project) and this resulted in two contractor bids. Currently, CPAU plans to replace as many aging mains as possible within its current budget. However, if this trend of higher construction cost continues, the Gas Utility may require larger CIP budgets and as a result, an increase in rates. This financial plan addresses these challenges in a way that will allow CPAU to meet its main replacement needs. This plan includes approximately $7 to 9 million every other year for main replacement construction instead of $5 to 6 million annually. This shift to larger main replacement construction projects every other year will lengthen the amount of time needed to replace all PVC pipes in the system, but will ideally attract more contractors to bid on the larger projects. Additionally, this main replacement project schedule for gas will be staggered with water and wastewater (water and wastewater construction every even year and gas construction every odd year), which will ease scheduling difficulties for inspection coverage due to shared inspection staff across water, wastewater, gas, and large development services projects. However, if staff sees a greater rate of failure of existing pipe materials, CIP projects may resume a more frequent schedule and may require additional rate funding needs. GMR 23 is slated to begin during FY 2021. However, work will also continue on outstanding main replacement projects in FY 2021 and into FY 2022. As staffing vacancies become filled and Project Category Current Budget * Spending, Curr. Yr. Remain. Budget **Committed FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 One Time Projects - - - - - - - - - Gas Main Replacement 8,960 (970) 7,990 7,662 2,000 7,000 2,000 9,000 2,000 Tools and Equipment 100 - 100 10 50 50 50 50 50 Ongoing Projects 695 (122) 573 255 1,500 1,500 1,000 1,000 1,000 Customer Connections 1,155 (386) 769 43 1,124 1,167 1,211 1,247 1,100 TOTAL 10,910 (1,478) 9,431 7,970 4,674 9,717 4,261 11,297 4,150 * Includes unspent funds from previous years carried forward or reappropriated into th ecurrent fiscal year ** Included with CIP Reserves (Reserve for Reappropriations + Reserve for Commitments) GAS UTILITY FINANCIAL PLAN January 2021 38 | Page construction costs stabilize, staff can re-evaluate the need to return to an annual replacement program. Staff projects ongoing projects, tools and equipment, and customer connections to cost approximately $2.7 million in FY 2022 and remain relatively flat at about $2.2 million through the end of the forecast period. In practice, these projects can fluctuate dramatically depending on prices of material, system conditions and the pace of development and redevelopment in the city. It is worth noting that fee revenue pays for the Customer Connections program, so when costs go up fees will be adjusted as well. Aside from customer connections and transfers from other funds, the CIP plan for FY 2021 to FY 2026 is funded by utility rates. Appendix B: Gas Utility Capital Improvement Program (CIP) Detail shows the details of the plan. SECTION 6D : 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. Table 16 shows debt service for this bond for the financial forecast period. Debt service on this bond will continue through 2026. Table 16: Gas Utility Debt Service FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2011 Utility Revenue Refunding Bonds, Series A 802 803 804 802 799 802 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”20 equal to five times the annual debt service. The current financial plan complies with these covenants throughout the forecast period, as shown in Table 17 and Table 18. 20 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities GAS UTILITY FINANCIAL PLAN January 2021 39 | Page Table 17: Debt Service Coverage Ratio ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Revenues 38,762 42,697 46,215 49,744 52,830 55,996 Expenses (Excluding CIP and Debt Service) (26,584) (30,930) (30,016) (32,404) (30,906) (34,474) Net Revenues 12,178 11,767 16,199 17,340 21,924 21,522 Debt Service 802 803 804 802 799 802 Coverage Ratio 1518% 1465% 2014% 2161% 2742% 2685% Table 18: Debt Service Minimum Reserves ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Gas Utility a 10,785 7,668 3,078 4,644 3,269 8,967 Debt Service b 802 803 804 802 799 802 Reserves Ratio c 13x 10x 4x 6x 4x 11x 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 total debt service and is higher than shown here. The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances listed in Table 19, 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 19: 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 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 6E : E QUITY T RANSFER The City calculates the equity transfer from its Gas Utility based on a methodology adopted by Council in 2009 that has remained unchanged since.21 Each year it is calculated according to the 2009 Council-adopted methodology, and does not require additional Council action. 21 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 January 2021 40 | Page SECTION 6F: REVENUES The Gas Fund receives most of its revenues from sales of gas, but about 10% comes from other sources. Interest income, service connection and capacity fees (the latter two being cost- recovery fees) are the main inputs, but a large source of revenue also comes from sales of allowances related to California’s cap-and-trade program. This latter source, however, is generally committed for specific programs which reduce greenhouse gas and are not usable as an offset to general expenses. Another revenue item related to the cap-and-trade program is collected in customers’ 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 customers’ 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. This financial plan bases sales revenue projections 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 customer behavior, as well as changes to more efficient gas appliances, or switching to electric appliances, will modify these forecasts. Staff continually evaluates forecasts to see when new trends emerge. SECTION 6G: COMMUNICATIONS PLAN The FY 2022 Gas Utility communications strategy covers these primary areas: operations, infrastructure, safety, efficiency, renewables, rates, and cost containment measures. The City of Palo Alto Utilities (CPAU) communication methods include use of the Utilities website, utility bill inserts, messaging on bills and envelopes, email newsletters, print and digital ads in local publications, videos and participation in community outreach events. Since moving to market pricing for commodity rates, the City of Palo Alto Utilities (CPAU) commodity rates can change monthly. Staff post these updates to the Utilities rates webpages. Consistent with the newly approved Utilities Strategic Plan, CPAU is instituting cost containment as an ongoing priority that is part of our annual cycle. In FY 2022, CPAU is proposing a 3 percent overall rate increase for the gas utility. However, we anticipate that gas distribution rates will need to increase about 5% in FY 2022 due to a resumption in capital improvement projects. Such maintenance and operations projects are important to maintain a safe and reliable gas distribution system. To keep customers apprised of the status and accomplishments of capital improvement projects, the City maintains a network of project web pages. Print and digital ads, social media and email blasts drive traffic to the website. CPAU promotes gas use efficiency incentives year-round, but most heavily during winter months to impact heating activities. CPAU continues to look for more ways to promote gas use efficiency GAS UTILITY FINANCIAL PLAN January 2021 41 | Page and awareness of the City’s carbon neutral natural gas utility. Programs such as the Home Efficiency Genie and commercial energy efficiency programs help residents and businesses better understand energy usage, activities and/or upgrades they can implement to improve efficiency and keep utility costs low. CPAU will be launching an upgraded version of its online utility account services portal this year, which can provide customers with direct access and more information about utility account and consumption data. CPAU emphasizes safety for all utility services year-round. Stepping up efforts to promote gas safety education, staff is focusing outreach among stakeholders to increase awareness of the need to call USA (811) before digging for anyone who may excavate in and around Palo Alto, such as plumbers and contractors. Staff is also focusing outreach on the importance of contacting CPAU to check for potential sewer and gas line cross-bores prior to clearing a sewer line. Additional outreach messaging includes keeping fats, oils and greases out of drains, and ensuring clear access to meters. CPAU has developed a number of safety outreach materials to distribute to customers at community outreach events, emergency preparedness fairs, school and business meetings. 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 and mails it to all customers in Palo Alto, as well as to emergency responders, public officials, plumbers, contractors and excavators that may work in and around the area. Staff talk with business customers at special facilities meetings, attend neighborhood safety and emergency preparedness fairs and offer presentations to school and community groups. While print materials and website pages still feature prominently, CPAU is increasing emphasis on outreach through email newsletters, direct mail, newspaper inserts, social media and online videos. The Gas Safety Public Awareness Plan contains saved copies of all outreach materials and logs of activities; the Department of Transportation typically reviews this Plan at least once per year. GAS UTILITY FINANCIAL PLAN January 2021 42 | Page 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 January 2021 43 | Page APPENDIX A: GAS FINANCIAL FORECAST D ETAIL 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1 RATE CHANGE (%)*0% 8% 0% 4% 5% 2% 3% 5% 5% 5% 0% 2 TOTAL SYSTEM AVERAGE RATE ($/Therm)1.050$ 1.212$ 1.203$ 1.340$ 1.289$ 1.386$ 1.536$ 1.580$ 1.677$ 1.791$ 1.817$ 0.841$ 0.891$ 0.935$ 1.002$ 1.082$ 1.068$ 3 SUPPLY COMPONENTS* ($/Therm)0.320$ 0.458$ 0.457$ 0.550$ 0.417$ 0.546$ 0.645$ 0.646$ 0.675$ 0.709$ 0.749$ 3 SALES IN THOUSAND THERMS 26,719 28,146 28,314 29,110 26,610 25,451 25,426 26,505 26,674 26,314 26,062 4 CHANGE IN RETAIL SALES REVENUE - 2,574 910 1,492 1,817 953 1,191 2,126 2,292 2,446 - 5 6 Utilities Retail Sales 28,065 34,110 34,056 39,017 34,294 35,283 39,062 41,890 44,742 47,121 47,365 7 Service Connection & Capacity Fees 961 940 1,078 997 902 1,145 1,124 1,167 1,211 1,247 1,100 8 Other Revenues & Transfers In 2,450 1,051 1,740 2,023 2,159 2,409 3,238 3,988 4,725 5,392 6,105 9 Interest plus Gain or Loss on Investment 712 13 22 1,404 1,139 691 432 529 525 677 678 10 Total Sources of Funds 32,188 36,115 36,895 43,441 38,494 39,527 43,856 47,574 51,203 54,437 55,248 11 12 Purchases of Utilities: 13 Supply Commodity & Cap and Trade 9,178 9,720 9,698 12,470 8,376 10,712 12,001 12,415 13,187 13,807 14,619 14 Supply Transportation (1,051) 2,843 3,223 3,487 2,727 3,178 4,406 4,698 4,822 4,852 4,901 15 Total Purchases 8,127 12,563 12,921 15,958 11,102 13,890 16,407 17,113 18,008 18,659 19,520 16 17 Administration (CIP + Operating)3,328 3,148 3,574 3,353 3,711 3,789 3,876 3,968 4,057 4,145 4,217 18 Customer Service 1,364 1,441 1,529 1,558 1,700 1,741 1,795 1,855 1,907 1,957 1,978 19 Demand Side Management 566 855 829 536 550 563 578 594 609 623 632 20 Engineering (Operating)426 355 351 400 666 681 697 515 528 540 548 21 Operations and Maintenance 4,153 4,321 4,673 4,957 5,334 5,460 6,693 6,875 5,965 6,117 6,188 22 Resource Management 472 566 357 401 463 474 489 506 520 534 539 23 Debt Service Payments 248 226 203 179 155 802 803 804 802 799 802 24 Rent 443 455 602 618 634 750 770 790 811 832 852 25 Transfers to General Fund 6,194 6,726 6,699 6,601 7,106 7,088 7,343 7,536 7,688 7,901 8,093 26 Other Transfers Out 303 510 808 704 521 531 541 961 980 999 1,018 27 Capital Improvement Programs 6,889 2,214 7,804 5,567 3,342 9,283 4,674 9,717 4,261 11,297 4,150 28 Total Uses of Funds 32,512 33,380 40,349 40,831 35,285 45,053 44,292 51,235 46,136 54,403 48,537 29 30 Into/ (Out of) Reserves (325) 2,735 (3,454) 2,610 3,209 (5,526) (436) (3,661) 5,067 34 6,711 31 32 Reappropriations + Commitments 7,167 5,407 8,674 11,251 3,662 3,662 3,662 3,662 3,662 3,662 3,662 33 Plant Replacement 0 0 0 0 0 0 0 0 0 0 0 Debt Service Reserve 816 813 795 795 804 804 804 804 804 804 0 34 CIP Reserve 3,820 3,820 3,820 3,820 3,820 3,820 0 0 1,000 0 2,000 35 Rate Stabilization 6,018 6,539 7,090 2,533 8,419 0 0 0 0 0 0 36 Operations Reserve 10,296 13,549 8,638 9,966 13,450 10,782 12,645 7,214 9,238 7,970 10,920 Cap and Trade Reserve 0 5,936 7,458 9,228 11,271 13,573 16,138 37 Unassigned 0 0 0 0 0 0 0 0 0 0 0 38 Total Reserves 28,117 30,128 29,017 28,365 30,155 25,003 24,568 20,907 25,975 26,009 32,720 39 1,148 2,011 (1,112) (651) 1,789 (5,151) (436) (3,661) 5,067 34 6,711 40 Short Term Risk Assessment Value 3,753 3,516 4,051 4,138 3,940 4,492 4,256 5,176 5,015 6,057 5,330 41 42 Operations Reserve Guidelines 43 Min (60 Days Commodity + O&M)5,000 5,518 5,727 6,172 5,251 6,565 6,512 6,825 6,884 7,086 7,297 44 Target (90 Days Commodity + O&M)7,500 8,277 8,590 9,258 7,876 9,848 9,769 10,237 10,325 10,629 10,945 45 Max (120 Days Commodity + O&M)10,000 11,036 11,454 12,344 10,502 13,130 13,025 13,650 13,767 14,172 14,593 46 City of Palo Alto Gas Utility Fiscal Year GAS UTILITY FINANCIAL PLAN January 2021 44 | Page APPENDIX B : GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL Project # Project Name Reappropriated/ Carried Forward from Previous Year Current Year Funding Spending, Curremt Year Remaining in CIP Reserve Fund Commitments FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 GAS MAIN REPLACEMENT (GMR) PROGRAM GS-12001 - Gas Main Replacement - Project 22 70,000$ 70,000$ 184,845$ (114,845)$ 37,020$ -$ -$ -$ -$ -$ GS-13001 - Gas Main Replacement - Project 23 120,651$ 7,740,697$ 98,336$ 7,642,361$ 7,167,485$ -$ -$ -$ -$ -$ GS-14003 - Gas Main Replacement - Project 24 -$ -$ -$ -$ -$ 2,000,000$ 7,000,000$ -$ -$ -$ GS-15000 - Gas Main Replacement - Project 25 -$ -$ -$ -$ -$ -$ -$ 2,000,000$ 9,000,000$ -$ GS-XXXXX - Gas Main Replacement - Project 26 -$ -$ -$ -$ -$ -$ -$ -$ -$ 2,000,000$ GS-18000 - Gas ABS/Tenite Replacement Project 1,149,062$ 1,149,062$ 686,961$ 462,101$ 457,160$ -$ -$ -$ -$ -$ Subtotal, Gas Main Replacement Programs 1,339,713$ 8,959,759$ 970,142$ 7,989,617$ 7,661,665$ 2,000,000$ 7,000,000$ 2,000,000$ 9,000,000$ 2,000,000$ TOOLS AND EQUIPMENT GS-13002 - Gas Equipment and Tools -$ 100,000$ -$ 100,000$ 10,250$ 50,000$ 50,000$ 50,000$ 50,000$ 50,000$ Subtotal, Tools and Equipment -$ 100,000$ -$ 100,000$ 10,250$ 50,000$ 50,000$ 50,000$ 50,000$ 50,000$ ONGOING PROJECTS GS-03009 - System Extensions - Unreimbursed -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ GS-11002 - Gas Distribution System Improvements 11,465$ 511,465$ 73,407$ 438,058$ 93,163$ 500,000$ 500,000$ 500,000$ 500,000$ 500,000$ GS-80019 - Gas Meters and Regulators 183,395$ 183,395$ 48,925$ 134,470$ 161,907$ 1,000,000$ 1,000,000$ 500,000$ 500,000$ 500,000$ Subtotal, Ongoing Projects 194,860$ 694,860$ 122,332$ 572,528$ 255,070$ 1,500,000$ 1,500,000$ 1,000,000$ 1,000,000$ 1,000,000$ CUSTOMER CONNECTIONS GS-80017 - Gas System, Customer Connections 72,365$ 1,155,053$ 385,738$ 769,315$ 42,869$ 1,124,169$ 1,166,894$ 1,210,901$ 1,247,228$ 1,100,000$ Subtotal, Customer Connections 72,365$ 1,155,053$ 385,738$ 769,315$ 42,869$ 1,124,169$ 1,166,894$ 1,210,901$ 1,247,228$ 1,100,000$ GRAND TOTAL 1,606,938$ 10,909,672$ 1,478,212$ 9,431,460$ 7,969,854$ 4,674,169$ 9,716,894$ 4,260,901$ 11,297,228$ 4,150,000$ Funding Sources Connection Fees 901,573$ 1,124,169$ 1,166,894$ 1,210,901$ 1,247,228$ 1,100,000$ Utility Rates/CIP Reserve 10,008,099$ 3,550,000$ 8,550,000$ 3,050,000$ 10,050,000$ 3,050,000$ GAS UTILITY FINANCIAL PLAN January 2021 45 | Page 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 January 2021 46 | Page 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: 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 a) 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. b) 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. c) 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. Section 8. Operations Reserve GAS UTILITY FINANCIAL PLAN January 2021 47 | Page 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. Section 10. Intra-Utility Transfers Between Supply and Distribution Funds GAS UTILITY FINANCIAL PLAN January 2021 48 | Page The Gas Utility records costs in two separate funds: 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. Section 11. Cap and Trade Program Reserve This reserve tracks revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the gas utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy), adopted by Council Resolution 9487 in January 2015. GAS UTILITY FINANCIAL PLAN January 2021 49 | Page 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 work 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 industry. 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 COMMUNICATIONS SAMPLES AVOID SANITARY SEWER ED JCKAGES Fats, Oils, and Grease (FOG) poured dram yoar st4 nuy cost sal money, tarns/ and ►mass* bt w2,1 so, 4 90.g 41.0%f t40., t.+x bra^ e! Pe*.Airs WNW rer W nary. Ima.rriti .m�. W'""9Fwa«, wow +ww.aa,*Var.cp ✓ � • rrla*.awor IMPORTANT CO nbt** VINI INPR xw /TN'. STAY SAFE AND WARM ALL WINTER W»« *«ter« «a« «a...x,. 1.,.,x10 xa.. Ww.rn ,. mw,«wa+w. n .asr. �uw� �nmw.r 5mxrx....w..w.w m w, ww,«wu...xuw•u.. mx aPxxwwrw. *w% SOW,* xxumw.e xut - -rwan u wwfiwe w 400.90041( ry Carbon Neutral EUCTPICtTY ANC NATURAL GAS APPENDIX C : GAS UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices shall be used when developing the Gas Utility Financial Plan: Section 1. Definition 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 Attachment C 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 and approved by Council resolution. Minimum Level 20% of the maximum CIP Reserve guideline level l Maximum Level Average annual (12 month)1 CIP budget, for 48 months of budgeted CIP expenses2 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 that reserve 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: 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 there are funds in this reserve in excess of the maximum level staff must propose in the next Financial Plan to transfer these funds to another reserve, return the funds to ratepayers, or designate a specific use of the funds for CIP investments that will be made by the end of the next Financial Planning Period. 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. The 1 Each month is calculated based upon 1/12 of the annual budget. 2 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to derive the annual average would be FY 2022 through FY 2025 etc. Council may approve exceptions to this requirement, when proposed by staff to provide greater rate stabilization to customers. 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. Section 10. Intra-Utility Transfers Between Supply and Distribution Funds The Gas Utility records costs in two separate funds: 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. Section 11. Cap and Trade Program Reserve This reserve tracks revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the gas utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy), adopted by Council Resolution 9487 in January 2015. RESIDENTIAL GAS SERVICE UTILITY RATE SCHEDULE G-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-1 Sheet No G-1-1 dated 7-1-2020 Effective 7-1-2021 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: ........................................................................................................$10.89 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 3. Transportation Charge ................................................................. $0.00-$0.15 4. Carbon Offset Charge .................................................................. $0.00-$0.10 Distribution Charge:....................................................................................... $0.5290 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 3. Transportation Charge ................................................................. $0.00-$0.15 4. Carbon Offset Charge .................................................................. $0.00-$0.10 Distribution Charge:............................................................................................. $1.3526 D.SPECIAL NOTES: 1. Calculation of Cost Components Attachment D-1 O CITYOF PALO ALTO UTILITIES RESIDENTIAL GAS SERVICE UTILITY RATE SCHEDULE G-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-2 Sheet No G-1-2 dated 7-1-2020 Effective 7-1-2021 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 Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced in the burning of natural gas. The Carbon Offset Charge will change in response to changing market conditions, changing sales volumes and the quantity of offsets purchased within the Council-approved per therm cap. The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation 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 O CITYOF PALO ALTO UTILITIES RESIDENTIAL GAS SERVICE UTILITY RATE SCHEDULE G-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-1-3 Sheet No G-1-3 dated 7-1-2020 Effective 7-1-2021 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} O CITYOF PALO ALTO UTILITIES 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 7-1-2021 dated 7-1-2020 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: ......................................................................................................$100.85 Per Therm Supply Charges: 1.Commodity (Monthly Market Based) .......................................... $0.10-$2.00 2.Cap and Trade Compliance Charges ........................................... $0.00-0.25 3. Transportation Charge.................................................................. $0.00-$0.15 4.Carbon Offset Charge .................................................................. $0.00-$0.10 Distribution Charge: .................................................................................................. $0.6948 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 Attachment D-2 O CITYOF PALO ALTO UTILITIES 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-2-2 Effective 7-1-2021 dated 7-1-2020 Sheet No G-2-2 volumes and the quantity of allowances required. The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced in the burning of natural gas. The Carbon Offset Charge will change in response to changing market conditions, changing sales volumes and the quantity of offsets purchased within the Council-approved per therm cap. The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will fall within the minimum/maximum ranges set forth in Section C. {End} O CITYOF PALO ALTO UTILITIES 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 7-1-2021 dated 7-1-2020 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 Gas Service. C. UNBUNDLED RATES:Per Service Monthly Service Charge:$461.43 Per Therm Supply Charges: 1. Commodity (Monthly Market Based) .................................................... $0.10-$2.00 2.Cap and Trade Compliance Charges ...................................................... $0.00-0.25 3. Transportation Charge .......................................................................... $0.00-$0.15 4. Carbon Offset Charge ........................................................................... $0.00-$0.10 Distribution Charge: .............................................................................................................$0.6879 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 Attachment D-3 O CIT Y OF PALO ALTO UTILITIES 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 7-1-2021 dated 7-1-2020 Sheet No G-3-2 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 Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced in the burning of natural gas. The Carbon Offset Charge will change in response to changing market conditions, changing sales volumes and the quantity of offsets purchased within the Council-approved per therm cap. The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation 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. {End} O CIT Y OF PALO ALTO UTILITIES 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 7-1-2021 dated 7-1-2020 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 the City’s CNG fueling station located at the Municipal Service Center in City of Palo Alto. C. UNBUNDLED RATES:Per Service Monthly Service Charge: ........................................................................................................$68.21 Per Therm Supply Charges: Commodity (Monthly Market Based) ................................................................ $0.10-$2.00 Cap and Trade Compliance Charges .............................................................. $0.00 to $0.25 Transportation Charge........................................................................................ $0.00-$0.15 Carbon Offset Charge ........................................................................................ $0.00-$0.10 Distribution Charge ...............................................................................................................$0.0113 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 Attachment D-4 O CITYOF PALO ALTO UTILITIES COMPRESSED NATURAL GAS SERVICE UTILITY RATE SCHEDULE G-10 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No G-10-2 Effective 7-1-2021 dated 7-1-2020 Sheet No. G-10-2 allowances required. The Carbon Offset Charge reflects the City’s cost to purchase offsets for greenhouse gases produced in the burning of natural gas. The Carbon Offset Charge will change in response to changing market conditions, changing sales volumes and the quantity of offsets purchased within the Council- approved per therm cap. The Transportation Charge is based on the current PG&E G-WSL rate for Palo Alto, accounting for delivery losses to the Customer’s Meter. The Commodity, Cap and Trade Compliance, Carbon Offset and Transportation Charges will fall within the minimum/maximum range set forth in Section C. {End} O CITYOF PALO ALTO UTILITIES March 03, 2021 www.cityofpaloalto.org GAS UTILITYFY 2022 FINANCIAL PROJECTIONS Staff: Eric Keniston and Lisa Bilir Attachment E • CITY OF PALO ALTO UTILIT 2 •FY 2022 Proposal: •3% increase for FY 2022 with no cost reductions. •Alternative proposal: 0% increase for FY 2022 with $5.4 million in one-time cost reductions. •Assumes sales decline 6% to 8% in FY 2022, and this seems to be holding for now. •If sales decline by 8% to 10%, additional $1 million expense reduction may be needed. •Future Years: •5% increases each year for FY 2023 through FY 2025 •Note: •Gas CIP (Gas Main Replacement (GMR) Project 24) has already been reduced by $2 million in FY 2023 in order to hold rate increases to 2% in FY 2021. •The cost reductions listed above required to hold rates flat for FY 2022 would be above and beyond cuts already implemented to GMR 24. Gas Rate Options ~CITY OF ~PALO ALTO 3 •Rate Design: •About one-third of the rate is “supply-related:” gas supply, transmission, and environmental charges. These rates vary monthly according to market-driven costs that are passed directly to customers •About two-thirds of the rate is set based on the City’s costs for maintaining its gas distribution system (gas mains, services, related equipment). These rates are being discussed here tonight. Gas Rate Design ~CITY OF ~PALO ALTO 4 Gas Utility Cost Structure Gas Distribution (in green): The cost to distribute gas within Palo Alto, including: maintaining and replacing gas infrastructure, customer service, billing, administration, etc. * Market -based pass-through costs. * * * ~CITY OF ~PALO ALTO I Capital 7 Investment $5 .6 mil lion L 13% ~ r Distributi on $19.1 million L 46% _J ~ Gas Supply ■ Di stribution Gas Suppl;l $12 .3 million 29% _J ~ 1Gas E nv· ron menta l ~ Ca pita I Investment Gas Enviro111menta I $2.4 mi l lion 6% Gas Transmission $3.S million 8% _J Gas T r a nsm ission 5 Long Term Cost Trends Annualized Increase, FY16-FY22: Annualized Increase, FY22-FY26: Supply, Environmental, Transmission: 14%/yr Supply, Environmental, Transmission: 4%/yr* Distribution: 5%/yr Distribution: 2%/yr Capital: 0.2%/yr Capital ** 3%/yr * Forecast is uncertain and will vary with the markets ** FY 2025 CIP is an average of two years due to staggered main replacement schedule. -V) 60 so C 4Q 0 - 10 ~CITY OF ~PALO ALTO FY 2016 FY 2022 (Projected)* Fy 2026 (Projected)* Gas Supply, Environmental, and Transmission Costs □ Capital Investment** Gas Operations 6 Gas Supply Cost Drivers •Gas supply –some volatility in gas market prices. Gas prices have risen in recent years as supplies have become tighter, demand has increased •PG&E gas transmission rates continue to rise to fund safety investments •Cap and trade costs continue to rise (as intended by design) •Carbon Neutral Gas Plan ~CITY OF ~PALO ALTO 7 Gas Distribution Cost Trends Annualized Increase, FY16-FY22: Gas Capital: 0.2%/yr* Gas Operations: 5%/yr Annualized Increase, FY22-FY26: Gas Capital: 3%/yr* Gas Operations: 2%/yr 40 35 30 "v,25 C: .0 20 ·-~ 15 - -v,. 10 5 FY 2016 FY 2022 (Projected)* Fy 2026 (Projected)* ■ Debt Service □ Operations Cap ita Investment ~CITY OF ~PALO ALTO • No main replacement project budget in FY 2020, 2022 & 2024 so CIP spending unusually low. Larger main replacement projects planned in FY's 2021 , 202 3 and 202 5. 8 Gas Distribution Cost Drivers •Health, retirement, and associated overhead costs continue to increase •Underground construction costs have increased substantially as well •Temporary funding ($1M/yr) for three years for crossbore investigations (project started in FY 2020, delayed due to COVID impacts) ~CITY OF ~PALO ALTO 9 Gas Sales Estimates -36 Ill C: .S! -Actual Purchases = 34 :?i ---Fast Recovery Ill cu Ill 32 RI -Medium Recovery .c u I,. :I -Deep Recovery Q. 30 E I,. cu .c I-28 26 24 22 20 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 ~CITY OF ~PALO ALTO 10 FY 2022 Preliminary Gas Cost and Revenue Projections Co s t / R e v e n u e $60 anges exc u mg supp y-re a anges 5% 0% 0% 8% 0% 4% 5% 2% 3% 5% $50 -Revenue $40 D Capital -Investment (/) C 0 □ Gas Supply :: $30 ~ -f:A-□ Operations $20 - ■ Transfers $10 - ■ Debt Service $0 c.o I'-co 0) 0 ~ N Cf) 'o:::t LO c.o ~ ~ ~ ~ N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N Actuals Projections .CITY OF PALO ALTO 11 Projected Gas Operating Reserve Projections $16 $14 $12 $10 vi" $8 C 0 , , ,----------, , ~ $4 $2 $0 ___ .. --··---··-··-· -· FY 2020 ~CITY OF ~PALO ALTO FY 2021 FY 2022 ----------- ---- - - -Reserve (Year-End) -Reserve Maximum _ .. -··-.. _ - -Reserve Target -··-··-··- -Reserve Minimum -Risk Assessment FY 2023 FY 2024 FY 2025 FY 2026 12 Estimated Bill Changes Residential Commercial Residential Usage Bill under Bill under (Therms/month) Current Rat,es Proposed Rates Winter (Using November 2020 commodity prices) 30 $ 41.88 $ 43.15 54 (med i an) 67.09 68.97 80 110.08 113.40 150 238.51 246.34 Summer (Us i ng October 2020 commodity prices) 10 $ 20.85 18 (med i an) 29.23 30 49.13 45 76.6 1 ~CITY OF ~PALO ALTO $ 21.62 30.20 50.79 79.24 Change $/mo. % $1.27 3.0% 1.88 2.8% 3.32 3.0% 7.83 3.3% $ 0 .77 3.7% 0.97 3.3% 1.66 3.4% 2.63 3.4% Usage Bill under Bill under Change (Therms/month} Current Rates !Proposed Rates % 500 685 706 3.1% 5,000 5,986 6,156 2.8% 10,000 11,875 12,211 2.8% 50,000 59,005 60,665 2.8% 13 Current Bill Comparisons Residential Commercial Residential Usage Season (therms} 30 W i nter (Med i an) 54 (December 80 2020) 150 10 Summer (Med i an) 18 (July 2020) 30 45 ~CITY OF ~PALO ALTO Palo Alto $ 40.97 65.45 106.09 232.40 $ 19 .31 26.46 44.51 69.69 % PG&E Zone X Difference 49.66 -17.5% 92.48 -29.2% 149.00 -28.8% 301.19 -22.8% 14.07 37.3% 26.77 -1 .2% 49 .86 -10.7% 78.72 -11.5% . . Gas Bill ($/month) % Usag,e (therms/mo) Palo Alto PG&E Difference 500 685 718 (5%} 5,000 5,986 6,831 (12%) 10,000 11,875 12,045 (1%) 50,000 59,005 51,419 15% 14 Monthly Residential Bill Comparison Palo Alto is 8% below PG&E average (CY 2019 data) $1 80 $1 60 $1 40 s .1 20 $1 00 $80 $60 $4 0 $20 $- PG&E Pa lo A Ito Su m er Su mme r -Lm,\I· (8 T hi m ) -M e d i an (18 T h ) -Hi g (28 T m ) -A ve age (22 Tum) ~CITY OF ~PALO ALTO PG &.E Pa lo .Al o W i nter Wi1 te r -Lo w (25 Thm) -Med iarn (54 T hi m) -Hl i g h (93 Thm) -A verage (68 Thi m:) 15 Alternate: FY 2022 Prelim Gas Cost and Rev Projections Co s t / Re v e n u e $60 $50 $40 -. en C 0 : $30 - ~ $10 - $0 ~CITY OF ~PALO ALTO anges exc u mg supp y-re a e 0% 8% 0% 4% 5% 2% 0% "° r--.. 00 (j') 0 n N n n n n N N N 0 0 0 0 0 0 0 N N N N N N N Actuals anges 5% ('(') N 0 N 5% o:::t" N 0 N Projections 5% LI) N 0 N 5% "° N 0 N -Revenue □ Capital Investment □ Gas Supply □ Operations ■ Transfers ■ Debt Service 16 Alternate: Projected Gas Operating Reserve Projections Includes $4.7M cost cuts FY 2023-2025$16 $14 $12 $10 -;;;-$8 C 0 ·- - $4 $2 $0 -·· FY 2020 ~CITY OF ~PALO ALTO ------ ----. . ...... . . ----. . -. . --. FY 2021 FY 2022 ----··-··-··__.,,..· FY 2023 FY 2024 ... ... ... -- ----,, --- .----··---··--. FY 2025 FY 2026 -Reserve (Year-End) -Reserve Maximum --Reserve Target -Reserve Minimum -Risk Assessment 17 RECOMMENDATION Staff requests that the UAC recommend that the Council: •Adopt a resolution approving: •The Fiscal Year 2022 Gas Financial Plan •Up to a $8.4 million transfer from the Rate Stabilization Reserve to the Operations Reserve in FY 2022 •Up to a $4.542 million transfer from the Operations Reserve to the Cap and Trade Program Reserve in FY 2021 •Amendments to the Gas Utility Reserves Management Practices •Adopt a resolution approving a 5% distribution rate (3% overall) increase to Gas Utility Rates ~CITY OF ~PALO ALTO City of Palo Alto (ID # 11883) Utilities Advisory Commission Staff Report Report Type: New Business Meeting Date: 3/3/2021 City of Palo Alto Page 1 Summary Title: FY 2022 Electric Financial Plan and Rates Title: Staff Recommendation That the Utilities Advisory Commission Recommend the City Council Adopt a Resolution Approving the Fiscal Year 2022 Electric Financial Plan and Reserve Transfers, and Amending Utility Rate Schedules E-EEC-1 (Export Electricity Compensation), E-NSE-1 (Net Surplus Electricity Compensation), E-2-G (Residential Master-Metered and Small Non- Residential Green Power Electric Service), E-4-G (Medium Non Residential Green Power Electric Service), and E-7-G (Large Non-Residential Electric Service) From: City Manager Lead Department: Utilities Recommendation Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council adopt a Resolution (Attachment A): 1.Approving the Fiscal Year (FY) 2022 Electric Financial Plan (Attachment B); 2.Approving a transfer of up to $5 million from the CIP Reserve to the Distribution Operations Reserve at the end of FY 2021; 3.Approving a transfer of up to $1 million from the Supply Operations Reserve to the ESP reserve at the end of FY 2021; 4.Approving an allocation of up to $1.189 million from the Cap and Trade Program Reserve at the end of FY 2021 to be spent on local decarbonization programs; 5.Updating the Export Electricity Compensation (E-EEC-1) rate to reflect current projections of avoided cost, effective July 1, 2021; 6.Updating the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect current projections of avoided cost, effective July 1, 2021; and 7.Updating the Palo Alto Green program pass-through premium charge on the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non- Residential Green Power Electric Service (E-7-G) rate schedules to reflect current costs, effective July 1, 2021. Staff: Eric Keniston and Lisa Bilir City of Palo Alto Page 2 Executive Summary The FY 2022 Electric Utility Financial Plan includes projections of the utility’s costs and revenues through FY 2026. Staff projects costs for the Electric Utility to increase steadily through the forecast period. Revenue increases between 0% to 5% are projected to be necessary to keep revenues in line with expenses over the next five years. Rising transmission costs are the primary contributor to the increases. A lack of precipitation, if it continues through the winter, may necessitate utilizing funds from the Hydroelectric Rate Stabilization Reserve starting in FY 2021. Operations costs are expected to increase at or near the inflation rate (2% to 3% per year) through the forecast period. Projected capital expenses are higher due to the rebuilding of existing underground districts, substation, the Foothills rebuild, and line voltage upgrades. The City is also evaluating the cost and scope of other system resiliency projects, such as pole replacements, which may increase costs as well as rates in the future. Electric loads have been gradually decreasing and are expected to continue to decrease in the long-term, mainly due to declining consumption in the commercial sector, putting gradual upward pressure on rates. This decline has been exacerbated by the COVID pandemic. Consumption is currently 5% to 10% below long-term consumption trends. Current models suggest that pandemic economic recovery will take place through 2021 and 2022, with electric consumption stabilizing on the long run average by 2023. Based on the relative health of the various Electric reserve funds, staff is recommending no rate increase for FY 2022, however this will likely result in reserves being close to the minimum guideline levels over the next two to three years. 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. The UAC reviewed preliminary financial forecasts at its December 2, 2020 meeting. Discussion Staff’s annual assessment of the financial position of the City’s electric utility is completed in compliance with cost of service requirements set forth in the California Constitution and applicable statutory law. The assessment includes making long-term projections of market conditions, of costs associated with the physical condition of infrastructure, and of other factors that could affect utility costs. Rates are then proposed that will be adequate to recover projected costs. City of Palo Alto Page 3 Proposed Actions for FY 2021 and FY 2022: The FY 2022 Electric Utility Financial Plan includes the following proposed actions: 1. Approving the Fiscal Year (FY) 2022 Electric Financial Plan (Attachment B); 2. Approving a transfer of up to $5 million from the Capital Improvement Project (CIP) Reserve to the Distribution Operations Reserve at the end of FY 2021; 3. Approving a transfer of up to $1 million from the Supply Operations Reserve to the ESP reserve at the end of FY 2021; 4. Approving an allocation of up to $1.189 million from the Cap and Trade Program Reserve at the end of FY 2021, to be spent on local decarbonization programs; 5. Updating the Export Electricity Compensation (E-EEC-1) rate to reflect current projections of avoided cost, effective July 1, 2021; 6. Updating the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect current projections of avoided cost, effective July 1, 2021; and 7. Updating the Palo Alto Green program pass-through premium charge on the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non- Residential Green Power Electric Service (E-7-G) rate schedules to reflect current costs, effective July 1, 2021. The transfer from the CIP Reserve will fund help fund CIP projects, keep the Distribution Operations reserve above minimum guideline levels and balance year to year changes in capital investment. The transfer to the Electric Special Projects reserve will work towards repaying the remaining $5 million of a $10 million short-term loan taken from the ESP reserve in FY 2018, during the last drought. Repaying the full $5 million in FY 2021, which was part of last year’s financial plan, is not recommended as the Supply Operations Reserve would likely go below the minimum guideline level in FY 2023 as a result. Instead, staff anticipates repaying the remaining balance in $1 million installments between FY 2021 and FY 2025. The City maintains a Cap and Trade Program Reserve within the Electric fund to hold revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the City’s electric utility. Cap and Trade Program revenues are provided to the elect ric utility to support a wide variety of carbon reducing activities, including local decarbonization. In accordance with Council’s August 2020 direction, (Staff Report #11556)1 the City has also exchanged certain types of renewable energy to take advantage of market conditions to reduce supply costs, fund electric utility programs and capital investment, and raise funds for local decarbonization. The revenues received from these REC exchanges are kept in the Electric City of Palo Alto Page 4 Supply Reserve. With this Financial Plan, and as described in Staff Report #11556, staff is allocating Cap and Trade funds equivalent to 1/3 of the FY 2021 REC Exchange program revenues, or $1.189 million, for future local decarbonization projects. Table 1 below shows the effects of the proposed transfers on reserve funds, as well as changes to the CIP min/max guidelines. The attached Electric Financial Plan (Attachment B) discusses these reserve changes in greater detail: City of Palo Alto Page 5 Table 1: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From) Reserves, Operations and Capital Reserve Guideline Levels for FY 2021 to FY 2026 ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Starting Reserve Balances 1 Supply Operations 29,429 25,213 20,120 19,588 23,351 28,131 2 Distribution Operations 9,064 10,808 10,729 10,282 11,415 13,836 3 CIP 5,880 880 880 880 880 9,880 4 Electric Special Projects 46,665 47,665 36,649 30,649 31,649 32,649 5 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400 6 Low Carbon Fuel Standard 6,340 4,080 3,186 2,164 1,092 524 7 Cap and Trade Program - 1,189 2,190 5,749 9,316 12,866 Revenues 8 Supply 112,482 114,293 118,332 124,988 124,256 124,120 9 Distribution 55,588 59,194 68,325 74,410 77,929 77,179 Transfers 10 Supply Operations (2,189) (2,000) (4,560) (4,567) (4,550) (3,700) 11 Distribution Operations 5,000 - - - (9,000) (3,000) 12 CIP (5,000) - - - 9,000 3,000 13 Electric Special Projects 1,000 1,000 1,000 1,000 1,000 - 14 Hydro Stabilization - - - - - - 15 Low Carbon Fuel Standard - - - - - - 16 Cap and Trade Program 1,189 1,000 3,560 3,567 3,550 3,700 Capital Program Contribution 17 Distribution Operations - - - - - - 18 CIP Reserve Expenses 19 Supply Expenses (114,509) (117,385) (114,305) (116,658) (114,925) (116,756) 20 Distribution Non-CIP Expenses (36,826) (40,645) (48,033) (41,578) (52,581) (53,466) 21 Planned CIP (22,018) (18,628) (20,739) (31,700) (13,926) (21,284) 22 ESP funded - (12,016) (7,000) - - - 23 Hydro funded - - - - - - 24 LCFS funded (2,260) (893) (1,022) (1,072) (568) (453) Ending Reserve Balance 1+8+10+19 Supply Operations 25,213 20,120 19,588 23,351 28,131 31,795 2+9+11+17+20+21 Distribution Operations 10,808 10,729 10,282 11,415 13,836 13,265 3+12+18 CIP 880 880 880 880 9,880 12,880 4+13+22 Electric Special Projects 47,665 36,649 30,649 31,649 32,649 32,649 5+14+23 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400 6+15+24 Low Carbon Fuel Standard 4,080 3,186 2,164 1,092 524 71 7+16 Cap and Trade Program 1,189 2,190 5,749 9,316 12,866 16,566 Operations Reserve Guidelines (Supply) 25 Minimum 17,508 17,981 18,461 19,177 18,892 19,193 26 Maximum 35,017 35,962 36,922 38,353 37,784 38,385 Operations Reserve Guidelines (Distribution) 27 Minimum 9,462 9,513 9,803 10,084 10,257 10,472 28 Maximum 15,128 15,152 15,654 16,138 16,402 16,750 CIP Reserve Guidelines 29 Minimum 5,005 4,700 4,232 3,803 3,635 3,499 30 Maximum 25,025 23,502 21,162 19,017 18,173 19,406 Due to the continuing COVID-19 pandemic and economic hardships created by it, the Utilities Department has chosen to propose a 0% rate increase opti on for FY 2022 and no more than 5% rate increases afterwards. Under this scenario, utility reserves are projected to drop to near their minimum guideline levels. Possible program and service cuts may be needed to make up the difference if the utility’s financial position ends up being worse than forecasted, but under City of Palo Alto Page 6 the assumptions used in this financial plan, existing reserves are anticipated to make up for revenue shortfalls due to the pandemic’s impacts. Table 2 below shows the new proposed rate trajectory and compares current rate projections to those projected in last year’s Financial Plan. Table 1: Projected Electric Rates, FY 2021 to FY 2025 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current 0% 5% 5% 2% 1% Last Year 0% 5% 5% 3% 0% FY 2022 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years Table 3 shows the projected rate adjustments over the next five years and their impact on the annual median residential electric bill (453 kwh per month in winter, 365 kwh per month in summer). Table 3: Projected Rate Adjustments, FY 2022 to FY 2026 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Electric Utility 0% 5% 5% 2% 1% Estimated Bill Impact ($/mo)* - $3.04 $3.19 $1.34 $0.68 * Estimated impact on median residential electric bill, which is currently $60.70 for CY 2020 The rate increases are related to several factors: increasing transmission costs, the need for substantial additional capital investment in the electric distribution system, potential low hydro supply, and increasing operations costs due to larger contracting needs to complete electric distribution system maintenance work. Revenues have also declined as customer usage has decreased, requiring larger rate increases to cover fixed expenses and offset the shortfalls. Historically, total electric utility costs (excluding short-term drought impacts) were roughly $120 million per year, allowing the electric utility to go without a rate increase from July 1, 2009 to July 1, 2016. Over the period from FY 2016 to FY 2018, though, annual costs (net of energy supply related revenue, like surplus energy sales) increased to roughly $140 million per year (costs were unusually low in FY 2019 due to some one-time savings from surplus energy sales). Costs are currently projected to increase to roughly $160 million by FY 2026 (net of surplus energy sales). Figure 1 shows the overall utility’s costs (net of surplus sales revenues) in FY 2016, FY 2022, and FY 2026. Costs for the electric supply portfolio have decreased slightly between FY 2016 and FY 2022, but much of this is due to surplus electric supply revenues that are not expected to continue indefinitely as well as the fact that customer sales have declined by 1.5% to 2% annually during this time. Assuming normal hydro conditions going forward, as well as a continuing trend of load loss, costs are projected to increase by about 1% annually for the City of Palo Alto Page 7 foreseeable future. Costs for managing the distribution system (e.g. maintenance, capital investment, customer service, billing, etc.) have increased as well, growing by about 3% per year on average in the past, and projected to grow by nearly 2-4% per year going forward. FY 2022 capital costs are higher due to the introduction of a large Smart Grid Technologies project, but these costs have been approved by Council to come from the Electric Special Projects Reserve and will not impact rates. Comparisons are difficult as FY 2016 capital costs were very low relative to normal years. Overall, costs are projected to increase by 2% per year over the forecast horizon, but declining loads will necessitate rate increases greater than this to maintain financial health. Figure 1: Electric Utility Costs, FY 201 6 Actual vs. FY 2022 and FY 2026 Projections Figure 2 shows electric distribution costs specifically. Capital costs have increased by about 4% per year on average over the last five years but are skewed in this graph due to a large ($17 million) Smart Grid Technology project budgeted for FY 2022 as well as very low spending during FY 2016. Going forward, increased costs are related to greater capital investment in the distribution system (e.g. underground district rebuilds, as well as substation upgrades). In the last few years, the City has experienced a higher number of outages in underground districts due to aging equipment and infrastructure. Distribution system operational spending is projected to increase by about 3% annually. Some of this is due to projected increases in costs of labor and materials. While there are higher than anticipated staff vacancies, external contracts will be used to enable staff to complete necessary electric system maintenance. City of Palo Alto Page 8 Figure 2: Electric Distribution Costs, FY 201 6 vs. FY 2022 and FY 2026 Projections While net electric supply portfolio costs stayed relatively stable from FY 2016 to FY 2022, this was mainly due to surplus energy revenues and decreasing loads driving down generation cost. Transmission cost increases and, to a lesser extent, operational ove rhead costs have increased by 8% annually in the same timeframe, as shown in Figure 3. In the future, staff forecasts that increased costs will continue largely come from transmission costs. These increases are due to rehabilitation and replacement of the existing statewide electric transmission system as well as expansion of that system to accommodate new generation, mostly renewable. Staff works to contain transmission costs through partner agencies, including the Transmission Agency of Northern California (TANC) and Northern California Power Agency (NCPA), and through direct partnerships with other local utilities (the Bay Area Municipal Transmission group, BAMx). These groups intervene in transmission proceedings at the Federal Energy Regulatory Commission (FERC) and the California Independent System Operator (CAISO), and have achieved some reductions in long-term transmission costs. Staff is beginning to look at strategies to achieve cost savings in electric supply and will discuss these strategies in greater detail in future meetings. City of Palo Alto Page 9 Figure 3: Electric Supply Costs, FY 2016 Actual vs. FY 2022 and FY 2026 Projections Staff also recognizes the importance of managing operating costs and maximizing efficiency in order to minimize rate increases. As discussed above, staff is working on cost containment measures related to transmission and renewable energy costs. Utility consumers also see some long-term cost savings from City-wide efforts to manage personnel costs. As reflected in the Utilities Strategic Plan, staff is exploring additional ways to effectively use available resources, particularly across Divisions. Electric Bill Comparison with Surrounding Cities For the median consumption level the annual residential electric bill for calendar year 2 020 was $728 under current CPAU rates, about 37% lower than the annual bill for a PG&E customer with the same consumption and approximately 19% higher 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 4 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, 2021. 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 tier s 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. City of Palo Alto Page 10 Table 4: Residential Monthly Electric Bill Comparison (Effective 1/1/2021, $/mo.) Season Usage (kwh) Palo Alto PG&E Santa Clara Winter 300 41.27 74.96 36.96 453 (Median) 69.22 113.19 56.50 650 107.37 174.55 81.66 1200 213.89 347.48 151.91 Summer 300 41.27 77.09 36.96 (Median) 365 52.18 97.53 45.27 650 107.37 187.14 81.66 1200 213.89 360.08 151.91 Table 5 shows the average monthly electric bill for commercial customers for various usage levels. Table 5: Commercial Monthly Electric Bill Comparison (1/1/2021, $/mo.) Usage (kwh/mo) Palo Alto PG&E Santa Clara 1,000 177 272 185 160,000 24,795 30,804 20,239 500,000 77,477 80,675 63,096 2,000,000 273,431 308,918 252,172 Net Energy Metering Buyback Rates The City operates two Net Energy Metering (NEM) programs. Solar customers served by the City of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail rates for electricity they export to the grid, and solar customers served by the NEM successor program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at the Export Electricity Compensation (E-EEC-1) rate for exported electricity. Customers on the NEM 1 program who have chosen to have the value of any annual net generation they produced over the past 12 months credited back to their account do so under the Net Metering Net Surplus Electricity Com pensation (E-NSE-1) rate, which is calculated using the utility’s avoided costs from the prior year. The Net Surplus Electricity Compensation rate represents the value of the City’s avoided costs or value of customer-generated electricity in Palo Alto during the prior calendar year, including compensation for the energy, avoided capacity charges, avoided transmission and ancillary service charges, avoided transmission and distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes. Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at the current retail rate for electricity drawn from the grid, and receive a credit for electricity they export to the grid at the Export Electricity Co mpensation (E-EEC-1) buyback rate. This buyback rate also reflects the avoided cost or value of customer-generated electricity in Palo Alto, City of Palo Alto Page 11 calculated on a forward-looking basis for the upcoming fiscal year. As shown in the table below, the current avoided cost for solar generation in Palo Alto is 10.78 cents/kWh, which is slightly higher than the avoided cost on the current NEM buyback rate (10.09 cents/kWh). This increase in the overall avoided cost is driven by a small increase in the value of the energy and in the City’s avoided transmission charges. Table 6: NEM Compensation Rates – Current vs. Proposed Rate Current $/kWh Proposed $/kWh Export Electricity (E-EEC-1) $0.1009 $0.1078 Net Surplus Electricity (E-NSE-1) $0.0877 $0.0992 Palo Alto Green (PAGreen) Program The PaloAltoGreen (PAG) program provides CPAU’s commercial customers an opportunity to voluntarily pay a premium to receive renewable electricity credits to match their energy usage. Under this program, CPAU staff purchase and retire Green-e certified renewable energy certificates (RECs) in the wholesale market on behalf of PAG customers. This enables participating commercial customers to claim credit for the REC purchases in order to satisfy their corporate sustainability goals and meet federal “green certification” requirements. The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium is intended to fully recover the costs of administering the program. The PAG program has very low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e verification process for the program), so the vast majority of the program cost is the purchase cost of the RECs. In the past year there has been a significant increase in the wholesale cost of Green-e certified RECs in the Western US market (from approximately $1.50/REC to $6/REC). As such, the PAG rate premium needs to be raised from $2 per 1,000 kWh block (2 cents/kWh) to $6 per 1,000 kWh block (6 cents/kWh). This change will be reflected on the Residential Master- Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non- Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules. Timeline The Finance Committee is scheduled to review the FY 2022 Electric Financial Plan in April 2021. The City Council will consider adopting the Financial Plan and rate amendments as part of the FY 2022 budget review and adoption process. Stakeholder Engagement The UAC reviewed preliminary financial forecasts at its December 2, 2020 meeting, and the Finance Committee reviewed the preliminary forecasts at its February 2, 2021 meeting. Staff City of Palo Alto Page 12 and the UAC’s recommendation on the FY 2022 Electric rate increases will go to the Finance Committee in April and be presented to City Council in June during the budget adoption process. Environmental Review The UAC’s review and recommendation to Council on the FY 2022 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: • Attachment A: Resolution • Attachment B: FY2022 Electric Financial Plan • Attachments C 1-5 • Attachment D: Presentation Attachment A * NOT YET APPROVED * 6055487 Resolution No. _________ Resolution of the Council of the City of Palo Alto Approving the Fiscal Year 2022 Electric Utility Financial Plan and Reserve Transfers and Amending Utility Rate Schedules E-EEC-1 (Export Electricity Compensation), E-NSE-1 (Net Surplus Electricity Compensation Rate), E-2-G (Residential Master-Metered and Small Non-Residential Green Power Electric Service), E-4-G (Medium Non- Residential Green Power Electric Service), and E-7-G (Large Non-Residential Green Power Electric Service) 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. 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. D. On ____, 2021, 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. The Council hereby approves the FY 2022 Electric Utility Financial Plan. SECTION 2. The Council hereby approves the following transfers as described in the FY 2022 Electric Utility Financial Plan: 1. Approve a transfer of up to $5 million from the Capital Improvement Project Reserve to the Distribution Operations Reserve; 2. Approve a transfer of up to $1 million from the Supply Operations Reserve to the Electric Special Project reserve; Attachment A * NOT YET APPROVED * 6055487 3. Approve an allocation of up to $1.189 million from the Cap and Trade Program Reserve for local decarbonization programs. SECTION 3. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-EEC-1 (Export Electricity Compensation) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-EEC-1, as amended, shall become effective July 1, 2021. SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-NSE-1 (Net Surplus Electricity Compensation Rate) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-NSE-1, as amended, shall become effective July 1, 2021. SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential 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, 2021. SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4-G (Medium Non-Residential 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, 2021. SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become effective July 1, 2021. SECTION 8. The Council makes the following findings: a. The 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. b. 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. // // // // // Attachment A * NOT YET APPROVED * 6055487 // SECTION 9. The Council finds that approving the Financial Plan does not meet the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative governmental activity which will not cause a direct or indirect physical change in the environment, and therefore, no environmental assessment is required. The Council finds that 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: ___________________________ ___________________________ Assistant City Attorney City Manager ___________________________ Director of Utilities ___________________________ Director of Administrative Services FY 2022 ELECTRIC UTILITY FINANCIAL PLAN FY 2022 TO FY 2026 Attachment B 2 | Page FY 2022 ELECTRIC UTILITY F INANCIAL PLAN FY 2022 TO FY 2026 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 .................................................................................. 8 Section 3: Detail of FY 2021 Rate and Reserves Proposals ....................................................... 8 Section 3A: Rate Design ............................................................................................................... 8 Section 3B: Current and Proposed Rates ..................................................................................... 8 Section 3C: Bill Impact of Proposed Rate Changes .................................................................... 10 Section 3D: Proposed Reserve Transfers ................................................................................... 11 Section 4: Utility Overview .................................................................................................. 12 Section 4A: Electric Utility History ............................................................................................. 12 Section 4B: Customer Base ........................................................................................................ 15 Section 4C: Distribution System ................................................................................................. 15 Section 4D: Cost Structure and Revenue Sources ...................................................................... 16 Section 4E: Reserves Structure ................................................................................................... 17 Section 4F: Competitiveness ...................................................................................................... 18 Section 5: Utility Financial Projections ................................................................................. 19 Section 5A: Load Forecast .......................................................................................................... 19 Section 5B: FY 2015 to FY 2019 Cost and Revenue Trends ........................................................ 21 Section 5C: FY 2019 Results ....................................................................................................... 22 Section 5D: FY 2020 Projections ................................................................................................ 23 Section 5E: FY 2021 – FY 2025 Projections ................................................................................ 23 Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 25 3 | Page Section 5G: Long-Term Outlook ................................................................................................. 31 Section 5H: Alternative Rate Projections ................................................................................... 33 Section 6: Details and Assumptions ..................................................................................... 33 Section 6A: Electricity Purchases ............................................................................................... 33 Section 6B: Operations .............................................................................................................. 35 Section 6C: Capital Improvement Program (CIP) ....................................................................... 36 Section 6D: Debt Service ............................................................................................................ 37 Section 6E: Equity Transfer ........................................................................................................ 38 Section 6F: Wholesale Revenues and Other Revenues .............................................................. 38 Section 6G: Sales Revenues ....................................................................................................... 39 Section 7: Communications Plan .......................................................................................... 40 Appendices ......................................................................................................................... 42 Appendix A: Electric Utility Financial Forecast Detail ................................................................ 43 Appendix B: Electric Utility Reserves Management Practices ................................................... 47 Appendix C: Description of Electric utility Operational Activities .............................................. 52 Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 53 4 | Page SECTION 1 : DEFINITIONS AND ABBREVIATIONS 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 sub-transmission 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 Sub-transmission 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 | Page SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Electric Utility for the next FY 2022 - 2026. 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 2A : OVERVIEW OF FINANCIAL POSITION The Electric Utility’s costs are projected to increase by about 2% per year on average from FY 2021 - 2026, as shown in Table 1. The majority of cost is related to electric supply purchases, which are increasing mainly due to increased transmission costs, and after the projected drop in consumption in FY 2021 due to the COVID crisis, are projected to grow at an estimated 2.5% per year on average. Operations and maintenance costs are about one third of total costs and are projected to increase by about 2% per year on average due to both inflationary as well as salary and benefits increases. Capital improvement costs are projected to rise steeply in the short term as the Smart Grid technology project gets underway, then stabilize to between $18 to $20 million a year thereafter. Ongoing projects will include rebuilds of existing underground districts as well as substation improvements and voltage conversion projects. Table 1: Electric Utility Expenses for FY 2020 to FY 2026 Expenses ($000) FY 2020 (act) FY 2021 (est) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Power Supply Purchases 90,646 93,402 96,219 98,071 102,284 104,443 106,133 Operations 52,497 60,020 60,762 63,245 64,965 61,611 62,543 Capital Projects 15,540 22,018 30,643 27,739 31,700 13,926 21,284 TOTAL 158,682 175,440 187,624 189,055 198,949 179,980 189,960 Due to the continuing COVID-19 pandemic and economic hardships created by it, the Utilities Department has chosen to propose a 0% rate increase option for FY 2022 and no more than 5% rate increases afterwards. Under this scenario, utility reserves are projected to drop to near their minimum guideline levels. Possible program and service cuts may be needed to make up the difference, but existing reserves are currently anticipated to make up for revenue shortfalls. Table 2 below shows the new proposed rate trajectory and compares current rate projections to those projected in last year’s Financial Plan. Table 2: Projected Electric Rates, FY 2021 to FY 2025 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current 0% 5% 5% 2% 1% Last Year 0% 5% 5% 3% 0% 6 | Page The Electric Utility maintains several reserves for the purposes of rate stabilization, such as the Hydro Stabilization reserve, which is used to mitigate against both dry and wet hydro conditions. The Electric Utility also has a CIP Reserve which is used to manage cash flow for capital projects, and fund capital contingencies such as unexpected spikes in CIP spending which do not merit separate bond financing. Table 3 shows the projected reserve transfers over the forecast period. Per Council approval, $10 million was transferred from the Electric Special Projects (ESP) Reserve in FY 2018 to the Operations Reserve to mitigate higher supply costs due to the drought, the costs of new renewable energy projects coming online and increasing transmission charges. Any transfers from the ESP Reserve require Council approval. $5 million was repaid in FY 2020, and staff anticipates repaying the remaining balance in $1 million installments between FY 2021 and FY 2025. During this time, withdrawals from the ESP Reserve for the Smart Grid Technologies project will also occur. In addition, in accordance with Council policy, staff will also fund the Cap and Trade Program Reserve with unspent revenues from the sale of carbon allowances freely allocated to the electric utility, as directed in Staff Report #11556 .1 Because of the possible economic impacts which may arise because of the ongoing COVID pandemic, staff is presenting all of these transfers as ‘up to’ amounts. If ending FY 2021 reserves are adversely impacted and/or FY 2022 outlooks for the Electric Utility change, staff may recommend transferring smaller amounts, or forgoing some of all of the transfers, as needed to keep the Operations Reserves within guideline ranges, to the greatest extent possible. 1 https://www.cityofpaloalto.org/civicax/filebank/documents/78046 7 | Page Table 3: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From) Reserves, Operations and Capital Reserve Guideline Levels for FY 2021 to FY 2026 ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Starting Reserve Balances 1 Supply Operations 29,429 25,213 20,120 19,588 23,351 28,131 2 Distribution Operations 9,064 10,808 10,729 10,282 11,415 13,836 3 CIP 5,880 880 880 880 880 9,880 4 Electric Special Projects 46,665 47,665 36,649 30,649 31,649 32,649 5 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400 6 Low Carbon Fuel Standard 6,340 4,080 3,186 2,164 1,092 524 7 Cap and Trade Program - 1,189 2,190 5,749 9,316 12,866 Revenues 8 Supply 112,482 114,293 118,332 124,988 124,256 124,120 9 Distribution 55,588 59,194 68,325 74,410 77,929 77,179 Transfers 10 Supply Operations (2,189) (2,000) (4,560) (4,567) (4,550) (3,700) 11 Distribution Operations 5,000 - - - (9,000) (3,000) 12 CIP (5,000) - - - 9,000 3,000 13 Electric Special Projects 1,000 1,000 1,000 1,000 1,000 - 14 Hydro Stabilization - - - - - - 15 Low Carbon Fuel Standard - - - - - - 16 Cap and Trade Program 1,189 1,000 3,560 3,567 3,550 3,700 Capital Program Contribution 17 Distribution Operations - - - - - - 18 CIP Reserve Expenses 19 Supply Expenses (114,509) (117,385) (114,305) (116,658) (114,925) (116,756) 20 Distribution Non-CIP Expense (36,826) (40,645) (48,033) (41,578) (52,581) (53,466) 21 Planned CIP (22,018) (18,628) (20,739) (31,700) (13,926) (21,284) 22 ESP funded - (12,016) (7,000) - - - 23 Hydro funded - - - - - - 24 LCFS funded (2,260) (893) (1,022) (1,072) (568) (453) Ending Reserve Balance 1+8+10+19 Supply Operations 25,213 20,120 19,588 23,351 28,131 31,795 2+9+11+17+20+21 Distribution Operations 10,808 10,729 10,282 11,415 13,836 13,265 3+12+18 CIP 880 880 880 880 9,880 12,880 4+13+22 Electric Special Projects 47,665 36,649 30,649 31,649 32,649 32,649 5+14+23 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400 6+15+24 Low Carbon Fuel Standard 4,080 3,186 2,164 1,092 524 71 7+16 Cap and Trade Program 1,189 2,190 5,749 9,316 12,866 16,566 Operations Reserve Guidelines (Supply) 25 Minimum 17,508 17,981 18,461 19,177 18,892 19,193 26 Maximum 35,017 35,962 36,922 38,353 37,784 38,385 Operations Reserve Guidelines (Distribution) 27 Minimum 9,462 9,513 9,803 10,084 10,257 10,472 28 Maximum 15,128 15,152 15,654 16,138 16,402 16,750 CIP Reserve Guidelines 29 Minimum 5,005 4,700 4,232 3,803 3,635 3,499 30 Maximum 25,025 23,502 21,162 19,017 18,173 19,406 8 | Page SECTION 2B : SUMMARY OF PROPOSED ACTIONS Staff proposes the following actions for the Electric Utility in FY 2021: 1. Approve a transfer of up to $5 million from the Capital Improvement Project (CIP) Reserve to the Distribution Operations Reserve; 2. Approve a transfer of up to $1 million from the Supply Operations Reserve to the Electric Special Projects (ESP) reserve; and 3. Approve an allocation of up to $1.189 million from the Supply Operations to the Cap and Trade Reserve. Staff proposes the following actions for the Electric Utility in FY 2022: 1. No increase to retail electric rates effective July 1, 2021; 2. Update the Export Electricity Compensation (EEC-1) rate to reflect current projections of avoided cost, effective July 1, 2021; 3. Update the Net Surplus Electricity Compensation Rate (E-NSE) rate to reflect current projections of avoided cost, effective July 1, 2021; and 4. Update the Palo Alto Green program pass-through premium charge on the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non- Residential Green Power Electric Service (E-7-G) rate schedules to reflect current costs, effective July 1, 2021. SECTION 3 : DETAIL OF FY 2022 RATE AND RESERVES PROPOSALS SECTION 3A : RATE DESIGN The Electric Utility’s rates are evaluated and implemented in compliance with cost of service requirements set forth in the California Constitution and applicable statutory law. This Financial Plan is based on staff’s assessment of the financial position of the Electric Utility, and updated using the methodology from the “City of Palo Alto Electric Cost of Service and Rate Study”2 drafted by EES Consulting, Inc. in 2015/16. The COSA is also based on design guidelines adopted by Council on September 15, 2015 (Staff Report 6061). SECTION 3B : CURRENT AND PROPOSED RATES The City adopted the current rates effective July 1, 2019, when CPAU increased electric rates by 8%. As the Utilities Department is currently not recommending a rate change for FY 2022, the current rates are the same as proposed rates, and are reflected in Table 4 below: 2 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274 9 | Page Table 4: Current and Proposed Electric Rates Current Rates Proposed Rates (7/1/2020) Change $ % E-1 (Residential) Tier 1 Energy ($/kWh) 0.13757 0.13757 No Change -% Tier 2 Energy ($/kWh) 0.19367 0.19367 - -% Minimum Bill ($/day) 0.3283 0.3283 - -% E-2 & E-2-G (Small Non-Residential) Summer Energy ($/kWh) 0.20853 0.20853 - -% Winter Energy ($/kWh) 0.14624 0.14624 - -% Minimum Bill ($/day) 0.8359 0.8359 - -% E-4 & E-4-G (Medium Non-Residential) Summer Energy ($/kWh) 0.12848 0.12848 - -% Winter Energy ($/kWh) 0.09946 0.09946 - -% Summer Demand ($/kW) 28.91 28.91 - -% Winter Demand ($/kW) 18.97 18.97 - -% Minimum Bill ($/day) 17.2742 17.2742 - -% E-7 & E-7-G (Large Non-Residential) Summer Energy ($/kWh) 0.11432 0.11432 - -% Winter Energy ($/kWh) 0.07738 0.07738 - -% Summer Demand ($/kW) 30.69 30.69 - -% Winter Demand ($/kW) 17.05 17.05 - -% Minimum Bill ($/day) 42.3648 42.3648 - -% Net Energy Metering Buyback Rates The City operates two Net Energy Metering (NEM) programs. Solar customers served by the City of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail rates for electricity they export to the grid, and solar customers served by the NEM successor program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at the Export Electricity Compensation (EEC-1) rate for exported electricity. Customers on the NEM 1 program who have chosen to have the value of any annual net generation they produced over the past 12 months credited back to their account do so under the Net Metering Net Surplus Electricity Compensation (E-NSE) rate, which is calculated using the utility’s avoided costs from the prior year. The Net Surplus Electricity Compensation rate represents the value of the City’s avoided cost or value of customer-generated electricity in Palo Alto, including compensation for the energy, avoided capacity charges, avoided transmission and ancillary service charges, avoided transmission and distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes. Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at the current retail rate for electricity drawn from the grid, and receive a credit for electricity they 10 | Page export to the grid at the Export Electricity Compensation (EEC-1) buyback rate. This buyback rate also reflects the avoided cost or value of customer-generated electricity in Palo Alto, calculated on a forward-looking basis for the upcoming fiscal year. As shown in the table below, the current avoided cost for solar generation in Palo Alto is 10.78 cents/kWh, which is slightly higher than the avoided cost on the current NEM buyback rate (10.09 cents/kWh). As the table indicates, this increase in the overall avoided cost is driven by a small increase in the value of the energy and in the City’s avoided transmission charges. Table 5: NEM Buyback Rates – Current vs. Proposed Rate Current $/kWh Proposed $/kWh Export Electricity (E-EEC) $0.1009 $0.1078 Net Surplus Electricity (E-NSE) $0.0877 $0.0992 Palo Alto Green (PAGreen) Program The PaloAltoGreen (PAG) program provides CPAU’s commercial customers an opportunity to voluntarily pay a premium to receive renewable electricity credits to match their energy usage. Under this program, CPAU staff purchase and retire Green-e certified renewable energy certificates (RECs) in the wholesale market on behalf of PAG customers. This enables participating commercial customers to claim credit for the REC purchases in order to satisfy their corporate sustainability goals and meet federal “green certification” requirements. The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium is intended to fully recover the costs of administering the program. The PAG program has very low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e verification process for the program), so the vast majority of the program cost is the purchase cost of the RECs. In the past year there has been a significant increase in the wholesale cost of Green-e certified RECs in the Western US market (from approximately $1.50/REC to $6/REC). As such, the PAG rate premium needs to be raised from $2 per 1,000 kWh block (2 cents/kWh) to $6 per 1,000 kWh block (6 cents/kWh). This change will be reflected on the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7- G) rate schedules. SECTION 3C : B ILL IMPACT OF P ROPOSED R ATE C HANGES As no rate change is proposed for July 1, 2021, there is no table showing the impact of rate changes. For more on comparisons of rates with surrounding agencies, see Section 4F: Competitiveness below. 11 | Page SECTION 3D : PROPOSED RESERVE TRANSFERS In FY 2018, Council approved a $10 million loan from the Electric Special Projects (ESP) reserve, and this financial plan includes full repayment by FY 2025. The pace of payback may be moderated based upon the general financial health of the electric fund. $5 million was repaid in FY 2020, and this financial plan assumes repayment of the remaining $5 million in $1 million installments by FY 2025. In addition, and based upon the actual ending balances of the Supply and Distribution Operations Reserves for FY 2021, staff requests withdrawing up to $5 million from the Capital Improvement (CIP) Reserve to both fund CIP projects and keep the Distribution Operations fund above minimum guideline levels. Staff further intends to add funds in the CIP reserve in future years, to keep its balance within guideline levels and to fund contingencies such as projected higher future CIP needs and costs. The City maintains a Cap and Trade Program Reserve within the Electric fund to hold revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the City’s electric utility. Cap and Trade Program revenues are provided to the electric utility to support a wide variety of carbon reducing activities, including local decarbonization. In accordance with Council policy, staff will fund the Cap and Trade Program Reserve with unspent revenues from the sale of carbon allowances freely allocated to the electric utility, as directed in Staff Report #11556 .3 In accordance with Council’s August 2020 direction, (Staff Report #11556)4 the City has also exchanged certain types of renewable energy to take advantage of market conditions to reduce supply costs, fund electric utility programs and capital investment, and raise funds for local decarbonization. The revenues received from these REC exchanges are kept in the Electric Supply Reserve. With this Financial Plan, and as described in Staff Report #11556, staff is allocating Cap and Trade funds equivalent to 1/3 of the FY 2021 REC Exchange program revenues, or $1.189 million, for future local decarbonization projects. Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2022 – FY 2026 Projections show the impact of these transfers on reserves levels. Table 5 shows the projected balance of each of the Electric Utility reserves for the period covered by this Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail 3 https://www.cityofpaloalto.org/civicax/filebank/documents/78046 12 | Page Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2019 to FY 2025 Ending Reserve Balance ($000) FY 2020 (Act.) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Re-appropriations - - - - - - - Commitments 3,519 3,519 3,519 3,519 3,519 3,519 3,519 Low Carbon Fuel Standard (LCFS) 6,340 4,080 3,186 2,164 1,092 524 71 Cap and Trade - 1,189 2,190 5,749 9,316 12,866 16,566 Underground Loan 727 727 727 727 727 727 727 Public Benefits 1,905 2,664 3,435 4,275 5,101 5,861 6,575 Special Projects 46,665 47,665 36,649 30,649 31,649 32,649 32,649 Hydro Stabilization 15,400 15,400 15,400 15,400 15,400 15,400 15,400 Capital 5,880 880 880 880 880 9,880 12,880 Rate Stabilization - - - - - - - Distribution and Supply Operations 38,494 36,192 30,832 29,629 33,771 39,372 42,368 Unassigned - - - - - - - TOTAL 118,928 112,314 96,817 92,991 101,454 120,798 130,754 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 Section 6: Details and Assumptions. SECTION 4A : 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 13 | Page customer than they had been 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. 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 Utility5 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 project 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 5 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997 14 | Page 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 manage 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 the Council adopted a goal of achieving 20% of its energy supply from renewables by 2015. Subsequently the City 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. 15 | Page SECTION 4B : 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 29,800 customers connected to the electric system, 25,700 (86%) of which are residential and 4,100 (14%) of which are non- residential. Residential customers consumed 152 gigawatt-hours (GWh) in FY 2020, approximately 18% of the electricity sold, while non-residential customers consumed 82% or 703 GWh. Residential customers use electricity primarily for lighting, refrigeration, electronics, and air conditioning.6 Non-residential customers use the majority of their electricity for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and refrigeration (grocery stores).7 As shown in Figure 1, Large customer loads represent the biggest proportion of sales for the Electric Utility. The proportion of sales to large vs. small customers is greater than for the City’s other utilities. For example, the largest customers (the 70 customers on the E-7 rate schedule) account for around 43% of CPAU’s sales. The next largest customer group (the 890 non- residential customers on the E-4 rate schedule) represents another 33% of sales. In total, that means that about 3% of customers account for nearly three quarters of the electric load. SECTION 4C : 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 472 miles of distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line transformers, around 1,100 underground and substation transformers, and the associated electric services (which connect the distribution lines to the customers’ homes and businesses). These lines, substations, transformers, and services, along with their associated poles, meters, and other associated electric equipment, represent the vast majority of the infrastructure used to deliver electricity in Palo Alto. 6 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 7 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Figure 1: Customer Consumption By Class (FY 2020) 18% 6% 33% 43%Residential Small Comm. Med. Comm. Large Comm. 16 | Page SECTION 4D : COST STRUCTURE AND REVENUE SOURCES As shown in Figure 2, electric commodity purchases accounted for roughly 57% of the Electric Utility’s costs in FY 2020. Operational costs represented roughly 33%, 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. Staff projects commodity supply costs to be approximately 56% of total costs in FY 2026. 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, projected, and low hydroelectric generation scenarios for FY 2020. Additional costs associated with a very low generation scenario can range from $9-11 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 79% 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, accounting entries that reflect things such as CPAU’s participation in a pre-funding program associated with its contract with WAPA, revenues from Figure 2: Cost Structure (FY 2020) 57% 33% 10% Commodity Supply Operations Capital Figure 3: Hydroelectric Variability (FY 2020) 0% 50% 100% 150% 200% Low Hydro Average High Hydro Surplus Hydro (sales) Market Power/RECs Hydro Renewables Load Figure 4: Revenue Structure (FY 2020) 79% 21% Sales of Electricity Other Revenue 17 | Page sales of surplus hydroelectric energy during wet years, as well as LCFS and Cap and Trade 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 960 largest customers, which provide a similar share of the utility’s revenue stream. About 25% of the utility’s revenue comes from peak demand charges on large non-residential 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 4E : RESERVES STRUCTURE CPAU maintains several reserves for its Electric Utility to manage various types of contingencies and for ease of reporting. It also maintains two funds, the Supply Fund and the Distribution Fund, to manage costs associated with electricity supply and electricity distribution, respectively. The City established this separation of supply and distribution costs as the City prepared to allow its customers a choice of electricity providers (referred to as “Direct Access”) 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 rates. This could be important if California ever decides to broadly reintroduce Direct Access, and is useful for rate design as the nature of utility services evolves in response to higher penetrations of distributed generation. Thus, individual reserves may reside within a particular fund (for instance, Electric Special Projects is under Electric Supply) or be included within both funds (there are both Supply and Distribution Reserves for Commitments). The summary below describes the various reserves, 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 re-appropriated by the City Council, nearly all of which are capital projects. Most City funds, including the General Fund, have a Re-appropriations 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). • 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 fund projects with significant impact that provide demonstrable value to electric ratepayers. 18 | Page • 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. • Cap and Trade Program Reserve: This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program. • Low Carbon Fuel Standard (LCFS) Reserve: This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, in accordance with California’s Low Carbon Fuel Standard program. • 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 can be used to accumulate funds for future expenditure on CIP projects, as well as to manage cash flow for ongoing capital projects. This reserve can also act as a contingency reserve for unforeseen capital expenses. This type of reserve is used in other utility funds (Water, 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 4F : COMPETITIVENESS For the median consumption level the annual residential electric bill for calendar year 2020 was $728 under current CPAU rates, about 37% lower than the annual bill for a PG&E customer with the same consumption and approximately 19% higher 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. 19 | Page 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, 2021. 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. Table 6: Residential Monthly Electric Bill Comparison (Effective 1/1/2021, $/mo.) Season Usage (kwh) Palo Alto PG&E Santa Clara Winter 300 41.27 74.96 36.96 453 (Median) 69.22 113.19 56.50 650 107.37 174.55 81.66 1200 213.89 347.48 151.91 Summer 300 41.27 77.09 36.96 (Median) 365 52.18 97.53 45.27 650 107.37 187.14 81.66 1200 213.89 360.08 151.91 Table 7 shows the average monthly electric bill for commercial customers for various usage levels. Table 7: Commercial Monthly Electric Bill Comparison (1/1/2021, $/mo.) Usage (kwh/mo) Palo Alto PG&E Santa Clara 1,000 177 272 185 160,000 24,795 30,804 20,239 500,000 77,477 80,675 63,096 2,000,000 273,431 308,918 252,172 SECTION 5 : UTILITY FINANCIAL PROJECTIONS SECTION 5A : LOAD FORECAST Figure 5 shows a 36-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. In recent years, some larger commercial customers have relocated operations or shifted to more commercial type usage. It is unknown how long this trend may continue, or what 20 | Page the longer term impacts of COVID and work-from home policies might mean for commercial utilization in Palo Alto. Figure 5: Historical Electricity Consumption Figure 6 shows the forecast of electricity consumption through FY 2026. The solid black straight line is the long term average trend of usage. The small-dash red line estimates the estimated drop in consumption due to the ongoing COVID response and is what was used for the current 0% scenario. Staff worked with Northern California Power Agency to incorporate UCLA’s Anderson School GDP forecast to estimate the impact of the COVID-19 pandemic. Based upon the forecast and the electricity load impact to date, the UCLA GDP forecast was added to capture the effect of the large and sharp COVID-19 recession through December of 2022. After this, the assumption is that sales will resume to at a level slightly below the long-term trend line. However, these projections will be revised if continuing sales patterns indicate further declines or increases, or changes in customer mix occur. 21 | Page Figure 6: Forecasted Electricity Consumption SECTION 5B : FY 2016 TO FY 2020 COST AND REVENUE TRENDS As shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail, the annual expenses for the Electric Utility remained fairly stable between FY 2015 and FY 2017 but increased in FY 2018. On the capital side, the large Upgrade Downtown CIP project got underway in FY 2018, which was a much larger project than usual. Electric supply costs increased as new renewable projects came online, and transmission costs rose and have continued to rise as improvements are made to the overall California grid. Section 6A: Electricity Purchases discusses the factors influencing Electric Utility expenses. Since FY 2012, total expenses for the utility have included the costs of renewable resources coming online. In FY 2014 through FY 2015 commodity costs were higher due to lower than average output from hydroelectric resources. Transmission costs have increased, as projected in prior financial plans. Better than average hydro conditions in FY 2019 led to lower than expected generation expenses as well as better than expected surplus energy revenues. Commodity costs have increased, on average, by about 4.6% per year over this timeframe. Operations costs have increased by about 2% annually on average. Revenues have increased on average by about 6% per year over this period, although FY 2018 sales revenues were lower than projected due to declining sales, and FY 2020 sales have been impacted by COVID. Actual Projection 22 | Page Figure 7: Electric Utility Expenses, Revenues, and Rate Changes: Actual Costs through FY 2019 and Projections through FY 2025 SECTION 5C : FY 2020 RESULTS FY 2020 saw lower sales than expected with the onset of the COVID pandemic, but other revenues (such as surplus energy sales) came in higher, offsetting the loss. Net purchase costs came in slightly higher than budget, and while O&M costs came in lower than projected, administrative and overhead costs came in higher. The net effect to the Operating Reserves were that they were $400,000 lower than estimated in the FY 2021 financial Plan. Table 8 FY 2020, Actual Results vs. Financial Plan Forecast ($000) Net Cost/(Benefit) Type of change Sales revenues higher than forecast $983 Revenue increase Surplus sales, interest, and other income higher than expected (1,068) Revenue increase Higher net purchase cost 435 Cost increase Higher operating expense 50 Cost increase Net Cost / (Benefit) of Variances $400 23 | Page SECTION 5D : FY 2021 PROJECTIONS Last year, staff recommended (and Council approved) no rate change for July 1, 2020. Sales are still declining but not as fast as projected earlier, and staff is estimating $4.8 million higher sales for FY 2021. Purchase costs are projected to increase by about $5.4 million, mainly due to poor projected hydro conditions. Other revenues are projected to be about $2.7 million higher, primarily from increasing EMA/Market sales (sales of surplus energy) as well as REC sales revenue. A revised operations cost outlook increased projected expenses by about $3.6 million compared to the FY 2020 Financial Plan, mainly from revised administration costs as FY 2020 actuals were higher. Programs funded by the City’s LCFS budget increased as well. With the increased sales outlook, net purchase costs are expected to be $5.4 million higher. Table 9 FY 2021, Change in Projected Results, 2022 Forecast vs. 2021 Forecast ($000) Net Cost/(Benefit) Type of change Modified reserve transfers (5,156) Operations Reserve increase Sales revenues higher than forecasted (4,834) Revenue increase Wholesale and other revenues higher than forecast (2,690) Revenue increase Purchased electricity costs higher than forecasted 5,440 Cost increase Operations costs 3,630 Cost decrease Net Cost / (Benefit) of Variances to Ops Reserve ($3,610) SECTION 5E : FY 2022 – FY 2026 PROJECTIONS As shown in Figure 7 above, staff projects costs for the Electric Utility to increase at a fairly steady rate through the forecast period. Revenue increases between 0% to 5% are projected to keep revenues in line with expenses over the next five years. Rising electricity purchase costs are the primary contributor to the increases. Electricity purchase costs are increasing substantially, as transmission costs rise to make improvements to the California grid. Operations costs are expected to increase at or near the inflation rate (2-3%/year) through the forecast period. Projected capital expenses are higher due to the rebuilding of existing underground districts, substation and line voltage upgrades. The City is also evaluating the cost and scope of other system resiliency projects, such as pole replacements, which may increase costs as well as rates in the future. The forecast also assumes the Smart Grid project to bring advanced metering to the Electric, Gas and Water utilities will start with $12 million in FY 2022 and additional $7 million in FY 2023. Funding for this project will come out of the Electric Special Projects reserve, as can be seen in Figure 8 below and in Appendix A: Electric Utility Financial Forecast detail. Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves), below. 24 | Page Figure 8: Electric Utility Reserves (Supply Fund): Actual Reserve Levels through FY 2020 and Projections through FY 2026 25 | Page Figure 9: Electric Utility Reserves (Distribution Fund): Actual Reserve Levels through FY 2020 and Projections through FY 2026 SECTION 5F : RISK ASSESSMENT AND RESERVES ADEQUACY The Electric Utility currently has two primary contingency reserves, the Supply Operations Reserve and the Distribution Operations Reserve. In the past, the Supply and Distribution funds had Rate Stabilization Reserves (RSR) but both have been drawn to zero, as approved in prior financial plans. In addition, the Electric Utility has a Hydro Stabilization reserve, an Electric Special Projects reserve and a Capital reserve, which can be utilized with prior Council approval. This Financial Plan maintains reserves above 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 is also currently within guideline levels. There are a variety of risks associated with the Supply Fund as are shown in Table 10. 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 10 is very low. 26 | Page Table 10: Electric Supply Fund Risk Assessment Categories of Electric Supply Cost Uncertainties Estimates of Adverse Outcomes (M$) Estimates of Adverse Outcomes (M$) FY 2022 FY 2023 1. Load Net Revenue 3.1 3.2 2. Hydro Production: Western & Calaveras 4.8 4.6 3. Renewable Production: Landfill & Wind & Solar 1.8 1.8 4. Carbon Neutral Cost 0.9 0.9 5. REC Sales 1.5 1.8 6. Market Price 0.3* 0.8** 7. Resource Adequacy 1.6 1.4 8. Transmission/CAISO 3.7~ 3.9~ 9. Plant Outage 1.0 1.0 10. Western Cost 1.6 1.6 11. Legislative & Regulatory 0.0 0.0 12. Supplier Default 0.2† 0.2† Electric Supply Fund Risks $ 20.5 million $ 21.0 million Of the risks faced by the Electric Utility’s Supply Fund, the risk of a dry year with very low hydroelectric output is normally the largest, accounting for nearly one-third ($4.8 million) of all the adverse cost uncertainty. Since the utility’s costs for its hydroelectric resources are almost entirely fixed, costs do not decline when the output of those resources are low, but the utility needs to buy power to replace the lost output. The converse happens when hydroelectric output is higher than average. Of the remaining risks for FY 2022, $3.7 million is related to potential transmission cost increases (above staff’s current forecast). $3.1 million is related to the potential that total load (and the associated retail sales revenue) may be lower than projected, $1.8 million is associated with uncertainty around renewables production, and $1.6 million is associated with possible decreases in Resource Adequacy capacity sales revenues (and/or increases in Resource Adequacy capacity purchase costs). As shown in Figure 10, staff projects the Supply Operations Reserve to remain slightly above the minimum guideline levels, dropping to its lowest in FY 2023 but recovering to target levels by FY 2026. Figure 11 shows that the combined Hydro Stabilization, Supply Rate Stabilization and 27 | Page Supply Operations Reserves are projected to be above what is needed for the risk assessment level. Figure 10: Electric Supply Operations Reserve Adequacy 28 | Page Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined Table 11 summarizes the risk assessment calculation for the Distribution Operations Reserve through FY 2026. As shown in Figure 12, the Distribution Operations Reserve is also projected to drop near to the minimum reserve guidelines in FY 2023, but is projected to recover to near target levels 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. 29 | Page Table 11: Electric Distribution Fund Risk Assessment ($000) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Total non-commodity revenue $55,969 $62,474 $67,870 $71,707 $71,475 Max. revenue variance, previous ten years 8% 8% 8% 8% 8% Risk of revenue loss $4,417 $4,931 $5,357 $5,659 $5,641 CIP Budget $30,643 $27,739 $21,700 $13,926 $21,284 CIP Contingency @10% $3,064 $2,774 $2,170 $1,393 $2,128 Total Risk Assessment value $7,482 $7,705 $7,527 $7,052 $7,770 Figure 12: Electric Distribution Operations Reserve Adequacy The Electric Utility also has a Capital Improvement Program (CIP) Reserve that acts as a reserve for short term capital contingencies or as a place to set aside funds for large, one-time projects that the Utilities would otherwise need to debt-fund. In the future, staff would also like to use this reserve to manage cash flow for capital projects on an ongoing basis as well. 30 | Page Figure 13 below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY 2021. Because of the fluctuating annual dollar amounts and timing of CIP projects budgeted to occur during the forecast period, as well as the potential for new ongoing projects to be included in the CIP plan in later years, four years of budgeted CIP is used to calculate the reserve maximum levels. The minimum CIP Reserve level is 20% of the maximum CIP Reserve guideline level. Because of constrained operating conditions resulting from the COVID epidemic and a desire not to raise rates too quickly, the 2022 Financial Plan doesn’t anticipate funding the CIP Reserve from the Distribution Operations Reserve until FY 2025 ($9 million). In future years, the CIP Reserve will reflect actual fluctuations in CIP expenditures (money spent on actual projects in a given year). CIP expenditures are currently reflected in the Operations Reserve. Staff is anticipating, once the CIP Reserve has an adequate ending balance, to annually fund the CIP reserve with an amount based on average anticipated CIP spending for that year (currently estimated at $18 to $19 million annually, but subject to change as new projects are added), and have any cost savings or over-runs be reflected in the CIP Reserve instead of the Operations Reserve, as described above. This will allow for better transparency and accounting of CIP related funds, will address uneven annual funding associated with ongoing CIP projects, and offer a funding source for one- time or immediately needed projects. Having the reserve guidelines in place will ensure the reserve has sufficient funding for budgeted CIP as fluctuating annual amounts of capital investment occur going forward. Figure 13 shows the projected CIP Reserve balances and guideline levels for FY 2021 through FY 2026, as well as the prior reserve and guidelines in FY 2020. Because of constrained financial conditions, the CIP reserve is projected to be below the minimum guideline for a few years, until reserve funding can take place. 31 | Page Figure 13: Electric CIP Reserve Adequacy SECTION 5G : LONG-TERM OUTLOOK This forecast covers the period from FY 2022 through FY 2026, but various long-term developments may create new costs for the utility over the next 10 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 contracts expire. Although 32 | Page 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 . Some additional debt may be issued to fund the costs of relicensing the project, but this is not anticipated to be as high as the current debt service. The project will only be 40 years old at that time, and hydroelectric projects can last for 70-100 years before major rebuilding is needed. 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 be a low-cost asset for the utility, providing carbon-free energy equal to around 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 programs and to purchase renewable energy to support the utility’s Carbon Neutral Plan. Staff expects that revenue source to continue through 2020. However, discussions at the state level are ongoing and will determine whether or not these allocations continue till 2030, as well as any further restrictions CARB may wish to enact on usage of allocation sales revenues. If the Electric Utility no longer received these allowances or was limited in how it could spend revenues, 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 33 | Page 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 continue to incorporate them into its planning methodologies. Over the long term, electricity may replace natural gas and petroleum almost entirely as part of the City’s efforts to combat climate change. Many, if not most, vehicles would use electricity, though hydrogen is another potential fuel source under development and other technologies might be developed. Staff are undertaking initial analysis of these types of scenarios 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 does not end up overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility distribution system management to accommodate integration of the various technologies involved in electrification. SECTION 5H: ALTERNATIVE RATE PROJECTIONS Staff has no alternative projections at this time. SECTION 6 : DETAILS AND ASSUMPTIONS SECTION 6A : ELECTRICITY PURCHASES As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a normal year (FY FY2015 was dry). Contracts with renewable sources made up just over 30% of the portfolio in FY 2016, and 50% in FY 2017. Staff expects contracts with renewable sources to continue at approximately 50% of the portfolio for the forecast period. 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. 34 | Page Figure 14: Electricity Supply by Source Figure 15 shows the historical and projected costs for the electric supply portfolio,8 as well as average and actual hydroelectric generation.9 Electric supply costs increased in FY 2013, FY 2014, and FY 2015 due to the drought, which reduced the amount of generation from hydroelectric resources. Costs decreased slightly in FY 2016 due to better than expected market purchase costs, and FY 2017 and FY 2018 had lower hydroelectric costs. Renewable energy costs assumed a larger portion of cost as various renewable projects came online to fulfill the City’s carbon neutral and RPS goals, although some of the older, higher priced contracts will start expiring as early as FY 2022. The current market outlook is that newer renewables projects should come in at lower costs. Transmission charges are also projected to increase as new transmission lines are built throughout California to accommodate new renewable projects. In total, electric supply costs are projected to increase to about $87 million by FY 2026, at which point all currently contracted renewable projects will be online. Supply costs are only projected to change slightly in subsequent years. 8 Costs are shown net of wholesale revenues, and cannot be directly compared with the electric supply purchase figures shown in Appendix A: Electric Utility Financial Forecast Detail. 9 Average hydroelectric generation based on the current E-HRA tariff. 35 | Page Figure 15: Electric Supply Portfolio Costs, Historical and Projected SECTION 6B : 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. From FY 2016 to FY 2020, overall Operations costs have risen annually by about 4% on average. Starting in FY 2021 and continuing for several years, Operations and Maintenance costs are 36 | Page increased mainly due to the introduction of a contract line crew to help while the Utility is understaffed. These costs may be reduced depending on how much work is needed and may be phased out as longer-term employees are gained. Demand side management costs are increasing in FY 2021 to reflect new and ongoing costs related to Low Carbon Fuel Standard rebates. Revenues from the same program will offset most of these costs. Figure 21: Historical and Projected Electric Utility Operational Costs SECTION 6C : CAPITAL IMPROVEMENT PROGRAM (CIP) Staff projects CIP spending for FY 2022 through FY 2026 to be consistent with last year’s forecast, though there is a slight shift in the funding by project category. There will be a reduction in funding for Undergrounding as current projects are completed and delayed; there will be an increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation; and increase in funding for replacement of distribution system and substation facilities that are at the end of their useful life. Other significant projects still slated to continue are deteriorated wood pole replacements, substation physical security upgrades, pole relocations to facilitate the Caltrain Railway Electrification project, Smart Grid upgrades, and ongoing capital investment in 37 | Page the electric distribution system to maintain/improve reliability. This forecast assumes that the utility finances smart grid projects (along with funding from the water and gas funds), the Foothill fire mitigation rebuilds, and the 115kV electric interconnection from the Electric Special Projects Reserve, but it would also be possible to use bond financing. The full deployment of the smart grid project has tentatively been moved out to start in FY 2023. Excluding the one-time projects listed above, the CIP plan for FY 2022 to FY 2026 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, foothill rebuilds, electric interconnection). The details of the CIP budget will be available in the Proposed FY 2022 Utilities Capital Budget. Figure 17 shows the FY 2022 projected budget and the five year CIP spending plan, although these figures are preliminary pending budget discussions starting in May. The ‘committed’ column represents funds committed to contracts for which work has not yet been completed or invoices paid. Figure 22: Electric Utility CIP Spending ($000) SECTION 6D : 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, the Electric Utility receives the RECs from these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are interest free (the investors receive a tax credit from the federal government). This 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 15: Electric Utility Debt Service ($000) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 2007 Clean Renewable Energy Bonds 100 100 - - - Project Category Current Budget * Spending, Curr. Yr. Remain. Budget **Committed FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 One Time Projects 4,456 (310) 4,146 265 4,000 2,000 2,000 11,000 - Reliability 3,531 (1,923) 1,609 1,042 4,020 5,690 4,040 3,000 2,563 Undergrounding 1,548 (35) 1,513 126 - 56 3,750 250 - 4/12 Kv Conversion 1,830 (7) 1,823 - 166 50 120 2,120 1,820 Underground Rebuild 4,955 (24) 4,931 17 2,110 250 400 4,050 461 Ongoing 3,766 (1,051) 2,715 1,169 5,830 4,445 3,805 3,605 3,672 Customer Connections 2,400 (1,515) 885 352 2,550 2,700 2,400 2,400 2,472 Total 22,486 (4,863) 17,623 2,971 18,676 15,191 16,515 26,425 10,987 * Includes unspent funds from previous years carried forward or re-appropriated into the current fiscal year. ** Equal to CIP Reserves (Reserve for Re-appropriations + Reserve for Commitments) 38 | Page 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 also pledges reserves and net revenue as security for the bond issuances listed in Table 16, 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 16: 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 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 6E : 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 since then.10 Each year it is calculated according to the 2009 Council-adopted methodology and does not require additional Council action. SECTION 6F : WHOLESALE REVENUES AND OTHER REVENUES The Electric Utility receives most of its revenues from sales of electricity, but about one quarter comes from other sources. Of these other sources, about 50% to 60% represents wholesale revenues of surplus energy sales. These revenues may offset electric supply purchase costs, smooth rate increases, or fund reserves or other costs. 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 2020 these sources represented roughly 33% of revenue from sources other than electricity sales. The remaining FY 2020 revenues consisted of a variety of one-time transfers. Revenues from connection fees have increased since FY 2009 varying from year to year. Connection fee revenues are collected to offset costs incurred in setting up new connections and are pass-through in nature. Revenue from connection fees decreased slightly during the recession, but has increased substantially since then, peaking in FY 2016 declining somewhat in 10 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. 39 | Page FY 2017 and FY 2018, then hitting a new high in FY 2019. Staff forecasts slightly lower revenue from this source in 2021 with revenue leveling out in subsequent years. Staff projects carbon allowance and interest income revenues to stay relatively stable through the forecast period. However, both of these revenue sources are subject to some uncertainty. This forecast assumes the program State’s cap-and-trade program will remain in place but with declining returns through 2030. This scenario may be pessimistic, but matches what has transpired for free allowances in the gas fund. 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 decrease (due to drought or a withdrawal from the ESP reserve for a major project), interest income would decrease. SECTION 6G : SALES REVENUES The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7 provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for this utility have been decreasing due to load reduction but are helped by the mild climate in Palo Alto. Palo Alto is a built-out City, so the opportunities for increased load growth are limited to the existing footprint of commercial structures and incremental growth in population. As utilization of existing spaces changes, and energy efficiency measures continue, Palo Alto could see greater load loss. Increased loads from electric vehicles and the electrification of households may increase loads somewhat. 40 | Page SECTION 7 : COMMUNICATIONS PLAN The fiscal year (FY) 2022 Electric Utility communications strategy covers these primary areas: efficiency services and utility bill savings; capital improvement, operations and maintenance for infrastructure safety and reliability; renewables and carbon neutral portfolio; beneficial electrification; and cost containment measures. The City of Palo Alto Utilities (CPAU) communication methods include use of the utilities website, utility bill inserts, messaging on utility bills, email newsletters, print and digital ads in local publications, social media, and community message boards. In FY 2022, CPAU is proposing no increase in electric utility rates. Communications will focus on helping customers with efficiency services, rate assistance and bill payment relief programs to help them navigate a challenging economic situation during the COVID-19 pandemic. They will also highlight CPAU’s decision to defer rate increases as a benefit of the organization’s management of its financial portfolio, including use of reserves for situations such as what we could not anticipate but observed in 2020. While the cost of transmission fees, capital investment, construction and contract labor costs have increased, CPAU is able to insulate customers against significant rate increases because of its financial portfolio management. Staff anticipates that rate increases around 5% each year beyond FY 2022 will be required in order to keep the reserves within a healthy margin. CPAU continues to make cost containment an ongoing priority and part of an annual cycle, consistent with the Utilities Strategic Plan. CPAU’s electric utility rates remain lower than the neighboring community average, such as for investor-owned utilities like PG&E. The average Palo Alto resident’s monthly electric bill is around 34% lower than the PG&E average. Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider. CPAU customers also benefit from local control and policy setting, and community values-driven programs and services, including the decision to go carbon neutral in 2013. Palo Alto’s renewable energy purchase agreements contribute to our utility’s long-term energy security and commitment to sustainability. 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. Programs such as the Home Efficiency Genie and commercial energy efficiency audits help residents and businesses better understand energy usage, activities and/or upgrades they can implement to improve efficiency and keep utility costs low. In 2020, we began offering a virtual Genie in-home assessment and webinars about home energy and water efficiency to help customers keep utility costs low while working and studying from home during the pandemic shelter-in-place order. CPAU is exploring additional opportunities to help customers electrify homes, buildings, and personal transportation. Rebates for residential appliances such as heat pump water heaters and electric vehicle charging stations for multi-family and non-profit facilities are incentivizing more and more customers to take action. Staff are piloting programs to explore electrification technologies in other applications as well. These efforts are in line with 41 | Page the City’s Sustainability and Climate Action Plan goals to reduce greenhouse gas emissions. CPAU launched an upgraded version of its online utility account services portal in 2020, which provides customers with direct access and more information about utility account and consumption data. 42 | Page 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 DETAIL 6053706 (page intentionally left blank) 6053706 1 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2 3 ELECTRIC LOAD 160 162 4 Purchases (MWh)977,292 945,703 925,329 905,071 879,913 818,593 835,246 870,922 875,208 867,019 858,859 5 Sales (MWh)937,157 917,687 899,997 884,322 854,760 796,450 812,790 846,966 851,449 843,454 835,431 6 7 BILL AND RATE CHANGES 8 System Average Rate ($/kWh)0.1156$ 0.1249$ 0.1413$ 0.1487$ 0.1624$ 0.1624$ 0.1624$ 0.1707$ 0.1799$ 0.1843$ 0.1837$ 9 Change in System Average Rate 0%10%13%5%9%0%0%5%5%2%0% 10 Change in Average Residential Bill 3%11%11%6%8%-1%-1%5%5%2%-1% 11 12 STARTING RESERVES 13 Reappropriations (Non-CIP)- - - - - - - - - - - 14 Commitments (Non-CIP)3,102,055 3,777,205 2,970,955 3,725,000 3,910,695 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 15 Low Carbon Fuel Standard (LCFS) Reserve - - - - - 6,340,000 4,079,577 3,186,120 2,163,917 1,091,927 524,278 16 Cap and Trade Program 1,189,129 2,189,551 5,749,259 9,315,900 12,866,019 17 Underground Loan Reserve 730,000 729,000 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659 18 Public Benefits Reserves 2,574,000 1,839,000 681,330 681,330 809,700 1,904,547 2,664,195 3,434,974 4,274,785 5,101,307 5,861,122 19 Electric Special Projects Reserve 51,837,855 51,837,855 51,837,855 41,837,855 41,664,855 46,664,855 47,664,855 36,649,107 30,649,107 31,649,107 32,649,107 20 Hydro Stabilization Reserve 17,000,000 11,400,000 11,400,000 11,400,000 11,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 21 Capital Reserves - - 879,964 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 9,879,964 22 Rate Stabilization Reserves 14,410,840 9,010,840 9,010,840 9,010,840 - - - - - - - 23 Operations Reserves 22,497,607 21,850,187 29,912,981 18,600,000 45,244,167 38,493,671 36,021,324 30,848,860 29,870,224 34,765,907 41,967,828 24 Unassigned - - - 244,354 - - - - - - - 25 TOTAL STARTING RESERVES 112,152,357 100,444,086 107,424,072 87,109,490 104,636,040 118,928,221 112,144,228 96,833,761 93,232,441 102,449,297 123,393,502 26 27 REVENUES 28 Net Sales 108,312,917 114,624,726 127,172,308 131,471,245 137,026,501 129,362,400 132,016,388 144,585,888 153,177,157 155,480,812 153,468,878 29 Wholesale Revenues 4,301,366 16,188,920 18,106,327 21,060,071 20,686,925 24,172,722 26,268,047 26,065,562 29,160,236 28,622,338 28,722,008 30 Other Revenues and Transfers In 11,714,494 11,225,911 13,373,312 19,914,635 15,260,935 16,958,432 15,201,708 16,006,051 17,060,870 18,081,320 19,108,217 31 TOTAL REVENUES 124,328,776 142,039,557 158,651,947 172,445,951 172,974,361 170,493,554 173,486,143 186,657,501 199,398,263 202,184,470 201,299,104 32 33 EXPENSES 34 Electric Supply Purchases 75,705,000 80,467,136 94,629,654 89,625,027 90,645,768 93,402,295 96,218,872 98,071,366 102,283,824 104,443,425 106,132,953 35 Operating Expenses 36 Administration 37 Allocated Charges 4,934,195 3,990,822 6,374,241 4,568,027 6,146,498 6,269,614 6,395,499 6,524,037 6,654,904 6,788,290 6,937,026 38 Rent 4,997,101 5,121,102 5,284,977 5,454,097 5,666,805 6,798,087 6,974,837 7,156,183 7,342,244 7,533,142 7,729,004 39 Debt Service 8,885,994 8,953,893 8,867,395 8,464,883 7,170,631 8,061,159 8,068,219 8,900,247 8,914,853 4,898,677 4,896,047 40 Transfers and Other Adjustments 11,798,865 13,052,376 13,632,059 13,342,321 10,200,181 13,859,349 14,460,996 14,618,796 14,996,752 15,004,867 15,013,144 41 Subtotal, Administration 30,616,155 31,118,193 34,158,672 31,829,328 29,184,115 34,988,209 35,899,551 37,199,262 37,908,752 34,224,975 34,575,221 42 Resource Management 2,083,812 1,985,620 1,873,954 2,082,405 2,849,071 2,915,597 2,999,304 3,091,930 3,174,074 3,252,752 3,337,994 43 Demand Side Management 3,643,924 4,271,786 3,889,846 3,655,547 2,733,047 6,813,274 5,597,849 6,226,330 6,735,444 6,579,673 6,835,735 44 Operations and Mtc 11,523,881 11,811,016 11,528,747 11,606,585 13,450,568 13,753,878 14,120,144 14,519,515 14,882,486 15,234,376 15,454,139 45 Engineering (Operating)1,592,024 1,656,522 1,790,942 1,838,799 2,051,303 2,093,560 2,138,697 2,185,640 2,231,923 2,278,475 2,321,056 46 Customer Service 1,540,884 2,190,993 2,291,246 2,180,400 2,228,469 2,281,952 2,351,324 2,428,904 2,496,527 2,560,731 2,589,553 47 Allowance for Unspent Budget - - - - - (1,413,087) (1,172,410) (1,203,369) (1,232,103) (1,260,236) (1,285,146) 48 Subtotal, Operating Expenses 51,000,680 53,034,130 55,533,407 53,193,063 52,496,573 61,433,382 61,934,458 64,448,212 66,197,103 62,870,747 63,828,552 49 Capital Program Contribution 9,331,367 11,558,306 18,803,467 10,770,456 15,539,840 22,017,870 30,643,280 27,739,243 31,700,480 13,926,093 21,284,122 50 TOTAL EXPENSES 136,037,047 145,059,572 168,966,528 153,588,546 158,682,181 176,853,547 188,796,610 190,258,821 200,181,407 181,240,265 191,245,628 51 52 ENDING RESERVES 53 Reappropriations (Non-CIP)- - 9,063,000 - - - - - - - - 54 Commitments (Non-CIP)3,777,205 2,970,955 8,637,000 3,910,695 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 3,518,525 55 Low Carbon Fuel Standard (LCFS) Reserve - - - - 6,340,000 4,079,577 3,186,120 2,163,917 1,091,927 524,278 71,297 56 Cap and Trade Program 1,189,129 2,189,551 5,749,259 9,315,900 12,866,019 16,565,994 57 Underground Loan Reserve 729,000 730,147 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 58 Public Benefits Reserves 1,839,000 681,330 681,330 809,700 1,904,547 2,664,195 3,434,974 4,274,785 5,101,307 5,861,122 6,574,538 59 Electric Special Projects Reserve 51,837,855 51,837,855 41,837,855 41,664,855 46,664,855 47,664,855 36,649,107 30,649,107 31,649,107 32,649,107 32,649,107 60 Hydro Stabilization Reserve 11,400,000 11,400,000 11,400,000 11,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 15,400,000 57 Capital Reserve - 879,964 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 9,879,964 12,879,964 58 Rate Stabilization Reserve 9,010,840 9,010,840 9,010,840 - - - - - - - - 59 Operations Reserve 21,850,187 29,912,981 18,600,000 45,244,167 38,493,671 36,021,324 30,848,860 29,870,224 34,765,907 41,967,828 45,060,895 60 Unassigned - - 244,354 - - - - - - - - 61 TOTAL ENDING RESERVES 100,444,086 107,424,072 101,084,490 104,636,040 118,928,221 112,144,228 96,833,761 93,232,441 102,449,297 123,393,502 133,446,979 62 6053706 1 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2 3 REVENUES 4 Net Sales 87%81%80%76%79%76%76%78%77%77%77% 5 Other Revenues and Transfers In 13%19%20%24%21%24%24%22%23%23%23% 6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100% 7 8 EXPENSES 9 Commodity Purchases 54%42%50%53%53%52%46%45%46%49%48% 10 Operating Expenses 11 Administration 12 Allocated Charges 4%3%4%3%4%4%3%3%3%4%4% 13 Rent 4%4%3%4%4%4%4%4%4%4%4% 14 Debt Service 7%6%5%6%5%5%4%5%5%3%3% 15 Transfers and Other Adjustments 9%9%8%9%6%8%8%8%8%8%8% 16 Subtotal, Administration 23%21%20%21%18%20%19%20%20%19%18% 17 Resource Management 2%1%1%1%2%2%2%2%2%2%2% 18 Operations and Mtc 8%8%7%8%8%8%7%8%8%8%8% 19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1% 20 Customer Service 1%2%1%1%1%1%1%1%1%1%1% 21 Allowance for Unspent Budget 0%0%0%0%0%-1%-1%-1%-1%-1%-1% 22 Subtotal, Operating Expenses 35%34%31%32%31%31%30%31%31%31%30% 23 Capital Program Contribution 7%8%11%7%10%11%16%15%11%8%11% 24 TOTAL EXPENSES 96%83%91%92%95%94%92%90%89%88%89% 25 26 RISK ASSESSMENT DETAIL (SUPPLY FUND) 27 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 28 1. Load Net Revenue 652,853 1,208,477 29 2. Hydro Production: Western & Calaveras 9,050,313 3,397,119 30 3. Renewable Production: Landfill & Wind & 743,945 539,073 31 4. Carbon Neutral Cost 303,022 114,983 32 5. Market Price 775,584 1,138,589 33 6. Local Capacity 408,388 446,695 34 7. Transmission/CAISO 3,741,647 2,806,120 35 8. Plant Outage 1,000,000 1,000,000 36 9. Western Cost 2,704,738 2,973,619 37 10. Regulatory & Legal - - 38 11. Supplier Default - - 39 TOTAL 19,380,490 13,624,674 40 Supply Operations + Hydro Stabilization Reserves, % of Risk Assessment 172% 303% 41 42 RISK ASSESSMENT DETAIL (DISTRIBUTION FUND) 43 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 44 Distribution Revenue Variance 3,260,213 3,182,718 3,742,109 3,915,276 4,447,787 4,432,418 4,417,304 4,930,733 5,356,652 5,659,448 5,641,151 45 10% CIP Program Contingency 933,137 1,155,831 1,880,347 1,077,046 1,553,984 2,001,787 3,064,328 2,773,924 2,170,048 1,392,609 2,128,412 46 Total Risk Asssessment Value 4,193,350 4,338,548 5,622,455 4,992,321 6,001,771 6,434,205 7,481,632 7,704,657 7,526,700 7,052,057 7,769,564 47 Projected Operations Reserve 21,850,187 29,912,981 18,600,000 45,244,167 38,493,671 36,191,535 30,831,986 29,628,922 33,771,081 39,672,192 42,667,847 48 Operations Reserve, % of Risk Value 521% 689% 331% 906% 641% 562% 412% 385% 449% 563% 549% 49 44 SUPPLY OPERATIONS RESERVE 45 Min (60 days of non-capital expenses)14,498,215 15,472,236 17,841,143 16,831,022 16,953,628 17,508,370 17,981,164 18,461,032 19,176,632 18,891,837 19,192,697 46 Target (90 days of non-capital expenses)21,747,322 23,208,354 26,761,715 25,246,533 25,430,442 26,262,555 26,971,747 27,691,548 28,764,949 28,337,756 28,789,046 47 Max (120 days of non-capital expenses)28,996,429 30,944,472 35,682,287 33,662,044 33,907,256 35,016,739 35,962,329 36,922,065 38,353,265 37,783,675 38,385,394 48 49 DISTRIBUTION OPERATIONS RESERVE 50 Min (60 days of non-capital expenses)8,513,675 9,755,012 8,008,309 7,869,900 8,621,917 9,462,487 9,512,586 9,802,609 10,084,238 10,256,803 10,471,541 51 Target (90 days of non-capital expenses)10,708,963 11,918,803 10,309,464 10,096,233 11,071,856 12,295,398 12,332,333 12,728,321 13,111,059 13,329,457 13,610,674 52 Max (120 days of non-capital expenses)12,904,252 14,082,593 12,610,618 12,322,566 13,521,795 15,128,308 15,152,079 15,654,034 16,137,881 16,402,112 16,749,808 53 Risk Assessment Value 4,193,350 4,338,548 5,622,455 4,992,321 6,001,771 6,434,205 7,481,632 7,704,657 7,526,700 7,052,057 7,769,564 54 55 DEBT SERVICE COVERAGE RATIO 56 Net Revenues (125% of Debt Service)1326%1391%1593%1587%1896%1821%1860%1726%1790%3315%3371% 57 Available Reserves (5x Debt Service)*10.9 11.7 9.4 11.9 16.1 13.5 11.6 10.1 11.0 24.0 26.0 58 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to mee ELECTRIC UTILITY FINANCIAL PLAN June 2018 47 | Page APPENDIX B : ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES 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) 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 11.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). ELECTRIC UTILITY FINANCIAL PLAN June 2018 48 | Page 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 timelines 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) Set a goal to commit funds by the end of FY 2017; f) Any uncommitted funds remaining at the end of FY 2022 will be transferred to the Electric Supply Operations Reserve and the ESP Reserve will be closed; Section 7. Hydroelectric Stabilization Reserve The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts associated with variations in generation from hydroelectric resources. Staff will manage the Hydroelectric Stabilization Reserve as follows: a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the actual and expected hydro output for that fiscal year, compare that to the long-term average annual output level (495,957 MWh as of March 2018), and multiply the difference by the average of the monthly round-the-clock forward market prices for each month of the current fiscal year. b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec. 7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro output deviations above long-term average levels, or transfer this amount from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output deviations below long-term average levels. c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after the transfers described above shall be the basis for staff’s determination, with Council ELECTRIC UTILITY FINANCIAL PLAN June 2018 49 | Page approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for the following fiscal year. d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve according to the following guideline levels: Minimum Level $3 million Target Level $19 million Maximum Level $35 million 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 and approved by Council resolution. Minimum Level 20% of the maximum CIP Reserve guideline level Maximum Level Average annual (12 month)11 CIP budget, for 48 months of budgeted CIP expenses12 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) 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. 11 Each month is calculated based upon 1/12 of the annual budget. 12 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to derive the annual average would be FY 2022 through FY 2025 etc. ELECTRIC UTILITY FINANCIAL PLAN June 2018 50 | Page d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff must propose in the next Financial Plan to transfer these funds to another reserve or return them to ratepayers in the funds to ratepayers, or designate a specific use of funds for CIP investments that will be made by the end of the next Financial Planning period. Staff may also seek City Council to 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. The Council may approve exceptions to this requirement, when proposed by staff to provide greater rate stabilization to customers. 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 11 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 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 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 ELECTRIC UTILITY FINANCIAL PLAN June 2018 51 | Page 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 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 Distribution 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 2017. 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. Section 15. Low Carbon Fuel Standard (LCFS) Reserve This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, as well as expenses incurred, in accordance with California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS Reserve will be adjusted by the net of revenues and expenses associated with California’s LCFS program. Section 16. Cap and Trade Program Reserve This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy), adopted by Council Resolution 9487 in January 2015. ELECTRIC UTILITY FINANCIAL PLAN June 2018 52 | Page APPENDIX C : DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL 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 representatives, 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 ELECTRIC UTILITY OUTREACH COMMUNICATIONS 04 .4, . 4 .n:. ...... • .,+A1 ?r w 4"w.{j,,, y, «.. oy, y nro dpi a +t f, THERE'S NO BETTER TIME TO INSTALL ELECTRIC VEHICLE (EV) CHARGERS AT YOUR BUSINESS EXPORT ELECTRICITY COMPENSATION UTILITY RATE SCHEDULE E-EEC-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1 dated 7-1-2019 Effective 7-1-2021 A. APPLICABILITY: This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for each Customer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate Schedule. This Rate 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: This Rate Schedule applies anywhere the City of Palo Alto provides Electric Service. C. RATE: The following buyback rate shall apply to all electricity exported to the grid. Per kWh Export electricity compensation rate $0.1078 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 electricity delivered and received after the Customer-Generator serves its own instantaneous load. b. CPAU shall bill the Customer-Generator consumption charges for the electricity delivered by CPAU to the Customer-Generator based on the Customer-Generator’s applicable Rate Schedule. c.In the event the electricity generated exceeds the electricity consumed and therefore is received by CPAU, the Customer will receive a credit for all electricity received by CPAU at the buyback Rate designated in section C above. {End} Attachment C-1 O CITYOF PALO ALTO UTILITIES NET METERING NET SURPLUS ELECTRICITY COMPENSATION UTILITY RATE SCHEDULE E-NSE-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-NSE-1 Sheet No.E-NSE-1 dated 07-01-2019 Effective 7-1-2021 A. APPLICABILITY: This Rate Schedule applies to eligible residential and small commercial Net Energy Metering Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus Customer-Generators of electricity who elect to receive monetary compensation as such preference is indicated on the net surplus electricity election form. This Rate Schedule only applies to Customers who participate in Net Energy Metering and does not apply to Customers that take Service under the City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation 2. B.TERRITORY: This Rate Schedule applies anywhere the City of Palo Alto provides Electric Service. C. RATES: Per kWh Net Surplus Electricity Compensation rate $0.0992 D. SPECIAL CONDITIONS 1.Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29. Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above compensation rate to determine the Customer’s annual net surplus electricity compensation stated in dollars. 2. Additional terms, conditions and definitions govern Net Energy Metering Service and Interconnection, as described in Rule 29. {End} Attachment C-2 O CIT Y OF PALO ALTO UTILITIES RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-2-G-1 Sheet No E-2-G-1 dated 7-1-2019 Effective 7-1-2021 A. APPLICABILITY: This Rate Schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities under the Palo Alto Green Program: 1.Small non-residential 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 $0.11855 $0.08551 $0.00447 $0.0060 $0.21453 Winter Period 0.08502 0.05675 0.00447 0.0060 $0.15224 Minimum Bill ($/day) 0.8359 2. 1000 kWh Block Purchase Option: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Summer Period $0.11855 $0.08551 $0.00447 $0.20853 Winter Period 0.08502 0.05675 0.00447 0.14624 Minimum Bill ($/day) 0.8359 Palo Alto Green Charge (per 1000 kWh block) $6.00 D.SPECIAL NOTES: Attachment C-3 0 CITY OF PALO ALTO UTILITIES RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-2-G-2 Sheet No E-2-G-2 dated 7-1-2019 Effective 7-1-2021 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 0 CITY OF PALO ALTO UTILITIES RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-2-G-3 Sheet No E-2-G-3 dated 7-1-2019 Effective 7-1-2021 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 if the Customer-s load is intermittent or subject to 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} 0 CITY OF PALO ALTO UTILITIES MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-4-G-1 Sheet No E-4-G-1 dated 7-1-2019 Effective 7-1-2021 A. APPLICABILITY: This Rate 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 Rate Schedule applies to three-phase Electric Service and may include Service to Master-metered multi-family facilities or other facilities requiring Demand metered Service, 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) $4.41 $24.50 $28.91 Energy Charge (per kWh) 0.10536 0.01865 0.00447 0.0060 0.13448 Winter Period Demand Charge (per kW) $2.75 $16.22 $18.97 Energy Charge (per kWh) 0.07634 0.01865 0.00447 0.0060 0.10546 Minimum Bill ($/day) 17.2742 Attachment C-4 • CITY OF PALO ALTO UTILITIES MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-4-G-2 Sheet No E-4-G-2 dated 7-1-2019 Effective 7-1-2021 2. 1000 kWh Block Purchase Option: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $4.41 $24.50 $28.91 Energy Charge (per kWh) 0.10536 0.01865 0.00447 0.12848 Palo Alto Green Charge (per 1000 kWh block) $6.00 Winter Period Demand Charge (per kW) $2.75 $16.22 $18.97 Energy Charge (per kWh) 0.07634 0.01865 0.00447 0.09946 Palo Alto Green Charge (per 1000 kWh block) $6.00 Minimum Bill ($/day) 17.2742 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 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. • CITY OF PALO ALTO UTILITIES MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-4-G-3 Sheet No E-4-G-3 dated 7-1-2019 Effective 7-1-2021 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 if the Customer’s load is intermittent or subject to 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 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 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 • CITY OF PALO ALTO UTILITIES MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-4-G-4 Sheet No E-4-G-4 dated 7-1-2019 Effective 7-1-2021 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 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 offered, but 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, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. 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. • CITY OF PALO ALTO UTILITIES MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-4-G-5 Sheet No E-4-G-5 dated 7-1-2019 Effective 7-1-2021 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} • CITY OF PALO ALTO UTILITIES LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-7-G-1 Sheet No E-7-G-1 dated 7-1-2019 Effective 7-1-2021 A. APPLICABILITY: This Rate Schedule applies to Demand metered Service for large non-residential 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) $5.03 $25.66 $30.69 Energy Charge (per kWh) 0.10932 0.00053 0.00447 0.0060 0.12032 Winter Period Demand Charge (per kW) $2.89 $14.16 $17.05 Energy Charge (per kWh) 0.07238 0.00053 0.00447 0.0060 0.08338 Minimum Bill ($/day) 49.1139 Attachment C-5 O CIT Y OF PALO ALTO UTILITIES LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-7-G-2 Sheet No E-7-G-2 dated 7-1-2019 Effective 7-1-2021 2. 1000 kWh Block Purchase Option: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $5.03 $25.66 $30.69 Energy Charge (per kWh) 0.10932 0.00053 0.00447 0.11432 Palo Alto Green Charge (per 1000 kWh block) $6.00 Winter Period Demand Charge (per kW) $2.89 $14.16 $17.05 Energy Charge (per kWh) 0.07238 0.00053 0.00447 0.07738 Palo Alto Green Charge (per 1000 kWh block) $6.00 Minimum Bill ($/day) 49.1139 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 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. O CIT Y OF PALO ALTO UTILITIES LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-7-G-3 Sheet No E-7-G-3 dated 7-1-2019 Effective 7-1-2021 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 if the Customer’s load is intermittent or subject to 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, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and which 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%. 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 O CIT Y OF PALO ALTO UTILITIES LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-7-G-4 Sheet No E-7-G-4 dated 7-1-2019 Effective 7-1-2021 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 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 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 offered, but 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, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. 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 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 O CIT Y OF PALO ALTO UTILITIES LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No E-7-G-5 Sheet No E-7-G-5 dated 7-1-2019 Effective 7-1-2021 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. {End} O CIT Y OF PALO ALTO UTILITIES March 03, 2021 www.cityofpaloalto.org ELECTRIC UTILITY FY 2022 FINANCIAL PROJECTIONS Staff: Eric Keniston and Lisa Bilir Attachment D • CITY OF PALO ALTO UTILIT 2 FY 2022 proposal: •0% overall increase Future years: •5% rate increases in FY 2023 and 2024 •Remaining Electric Special Project Reserve loan repayment rescheduled, annual repayments of $1 million per year. •Reserve margins are minimal in this scenario. Some combination of reserve withdrawals, cost reductions, or rate increases may become necessary if sales forecasts worsen or energy costs rise. Electric Rate Proposal ~CITY OF ~PALO ALTO 3 Electric Utility Cost Structure Electric Distribution costs (in green): $51 million 39% Electric Supply: The cost to buy electricity and transport it to Palo Alto, including operational overhead (e.g. energy scheduling) Electric Supply costs (in blue): $82 million 61% Electric Distribution: The cost to distribute electricity within Palo Alto, including: maintaining and replacing electric infrastructure, customer service, billing, administration, etc. ~CITY OF ~PALO ALTO 31% □ Generat ion ■ Operat i ons 8% 41% 15% ~ Transm i ss i on □ Supp ly Overhead D Cap ita l I nvestment 4 LONG TERM COST TRENDS Annualized Increase, FY16-FY22: Annualized Increase, FY22-FY26: Supply: -0.2%/yr Distribution: 10.6%/yr Supply: 1.9%/yr Distribution: (2.1)%/yr • . CITY OF PALO ALTO ..-.. en C: 0 ·--·-~ .._. -V). 180 1 160 140 120 100 80 160 40 20 IFY 2022 (Projected) Fy 2026 (Projected) El ectri c !D i stri buti on Electri c Supp ly 5 LONG TERM COST TRENDS: SUPPLY Annualized Increase, FY16-FY22: Annualized Increase, FY22-FY26: Transmission: 9.8%/yr Generation: -4.3%/yr Transmission: 10.3%/yr Generation: -2.4%/yr Overhead: 11.6%/yr Overhead: 3.1%/yr • . CITY OF PALO ALTO 100 80 -60 V) C: 0 40 ~ --tn-20 ~ . --.. --.. --. ---. --.. --. . --.. --.. --I•■ 1 I ■■ I I ■■ I I ■■ IO ■■ I I ■■ I ■■ I I ■■ I I ■■ I I ■■ I I ■■ I I ■■ • • ,. ~ • • " • ' ., • I . - -.. --.. - -. ---. - --. - -. . - -.. --.. - - I ■■ I I ■■ I I ■■ I 0 ■■II ■■ I 1 ■ ■ . ---. ---. --· L ... ,. .... ,. ..... ............... ............... ~ ............... ............... ~ ............... --■111\.■--■l\.■--■•1 ............... ................ ~ ............... ................ ~ ................ ............... ~ ................ ................ ~ ............... ............... ~ ............... ................ ~ ............... .. ■I\.■ ... ,. ..... ............... ................ ~ ............... ............... ~ ................ ................. 1 ............... --■111\.• .. •l\.• .. ••1 ............... .. -~-... -,. . ._ -~ ~ Generation FY 2022 (Projected) Transmission Fy 2026 (Projected) Eml Overhead 6 Supply Cost Drivers •Overhead costs have decreased as NCPA has sought revenue by providing services to more agencies. •Transmission costs have increased dramatically –system replacement, new lines to integrate new generators. CPA partners with others to advocate for cost control. •Renewable projects have come online. In the longer term, generation costs should stay fairly stable due to CPA’s long- term fixed price contracts ~CITY OF ~PALO ALTO 7 LONG TERM COST TRENDS: DISTRIBUTION Annualized Increase, FY16-FY22: Annualized Increase, FY22-FY26: Capital: 38.7%/yr Operations: 4.2%/yr Capital: (13.9)%/yr Operations: 3.0%/yr • . CITY OF PALO ALTO -V) C: 0 ~ --tll- 90 80 70 60 50 40 30 20 10 FY 2016 Debt Service FY 2022 (Projected) Fy 2026 (Projected) □ Operations Capital Investment 8 Distribution Cost Drivers •Medical/retirement benefit costs and associated overhead costs continue to increase •Increased capital investment in the electric distribution system needed due to system age •Underground construction costs have increased substantially •Additional contract expense for line crew until internally staffedUJ ,11. rn I I ~CITY OF ~PALO ALTO 9 Monthly Residential Electric Bill Comparison Palo Alto is 37% below PG&E average $,250 $,200 $,1 50 $,100 $50 $- PG&E Palo Alto SL!lm er Suimme r -Lo w [190 kWh ') -Medi an (365, kWh) -High (755 kWh) -Ave age (460 .wh) ~CITY OF ~PALO ALTO PG&E Pa lo Al o W i n te Wiinte1r -Low (230 11::Wh) -Med ian 1[453 kWh) -Hug h (88 01 ll::Vilh) -Average (540 kWh.] 10 Electric Bill Comparison: Effective Jan 1, 2021 Residential Commercial Season Usage (kwh) 300 Wi11 ter 453 (M e d iia n)i 650 1200 300 Summer (M e di a n) 36S 650 1200 ~CITY OF ~PALO ALTO - Palo Alto IPG&E 41.27 74.96 69.22 113.19 107.3 7 174.5,5 213.89 .347.48 41.27 77.09 52.18 97.5,3, 107.37 187.14 213.89 360.08 Santa Clara .36.96 .56.50 81..66 151.91 36.96 45 .27 81..66 151.91 -- Usage· (kw h/ m 9J Palo Alto PG&E Santa Cla r a 11000 177 .272 185 1601000 241795 30,804 20,239 500,1000 77/177 80,675 63,096 21i0001000 273143:1 308,918 .252 ,1.72 11 FY 2021 Updated: Electric Cost and Revenue Projections Co s t / R e v e n u e Ill C .2 :ii! ~CITY OF ~PALO ALTO $200 $150 $100 $50 $0 11% 14% RATE CHANGES: 6% 8% 0% 0% 5% 5% 2% 1% --------------------------------------------------------------------------------------------------------=------"'"'--""'--""'---.... -----------· :m:: ~~,~=-M:lectric Commodity c;::;::;JCapital Investment l::::::,:::,J Tr a nsf e rs i c::::J Operations ----Debt Serv i ce --Revenue I.O r---00 O'I 0 .--i N C'Y") q-L.f') I.O .-t .-t .-t .-t N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N >- >- >- >->->- >- >- >- >- >-LL LL LL LL LL LL LL LL LL LL LL Actuals Projections 12 Electric Supply Operating Reserve Projections VI $45 C .Q ~ $40 +-------------------------------------- $35 ······--=:=::;::::;---------~---~---~----::: ... ::: ... :: .... :: ... :: .. =::::::::=---------------- $30 -+---------------------------------- ----- $25 $20 ,--_-_-_-_-_-_-_-_-_-_-_-_-_-_-_-___ .....::_-_-_-_--_=_~;;:;__~=::,:;; _ _..._ .... ~-=---_-_-_-_:::::...::.:::..::.:::..=-_-_-_-_-_-_-_-_-_-_-_-_~:::::__=--- $15 -Reserve Maximum $10 -+----------------------------~-es-erve ·"farget---- -Reserve Minimum $5 -Reserve (Year-End) FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 ~CITY OF ~PALO ALTO 13 Electric Supply Reserve Adequacy $50 $40 $30 $20 $10 $0 ~Hydro Stabilization Reserve (Year- End) till Operations Reserve (Year-End) -Risk Assessment FY 2020 FY 2021 FY 2022 ~CITY OF ~PALO ALTO FY 2023 FY 2024 FY 2025 FY 2026 14 Electric Distribution Operating Reserve Projections "'$18 ~------------------------------------- c g :?i $16 +---------------=:::::::;;;;;;;----~~:::::===========--- --------------$12 -------------.,,..,...-~ ... ------------------/------------ ... ... ... $8 -----------·----------------------------------.. -- $6 $4 .. --··.,,,,.,,-..,__._ .. ---♦-··-··-··-··-··-··-··--··--··--· -Reserve Maximum - -Reserve Targ~et __ _ -Reserve Minimum $2 -------------------------------------_-_,...eserve(Year-Fnd) ---- -Risk Assessment ~CITY OF ~PALO ALTO FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 City of Palo Alto (ID # 11885) Utilities Advisory Commission Staff Report Report Type: New Business Meeting Date: 3/3/2021 City of Palo Alto Page 1 Summary Title: FY 2022 Water Financial Plan and Rates Title: Staff Recommendation That the Utilities Advisory Commission Recommend the City Council Adopt a Resolution Approving the Fiscal Year 2022 Water Utility Financial Plan, With no Water Rate Increase for Fiscal Year 2022 From: City Manager Lead Department: Utilities RECOMMENDATION Staff requests that the Utilities Advisory Commission (UAC) recommend that the Council: 1.Adopt a resolution (Attachment A) approving: a.The Fiscal Year (FY) 2022 Water Utility Financial Plan (Attachment B); and b.A transfer of up to $13.24 million from the Operations Reserve to the CIP Reserve in FY 2022. EXECUTIVE SUMMARY The FY 2022 Water Utility Financial Plan includes projections of the utility’s costs and revenues for FY 2021 through FY 2026. Costs are projected to rise by about 4% per year over the next several years. Capital projects were deferred in FY 2017 through FY 2020 leading to lower capital costs than budgeted. Many of these deferred capital projects are anticipated to be completed in FY 2021 and FY 2022 and a combination of funds from the Operations and CIP Reserve are available for those in the year end 2020 balances. Although capital investment needs will fluctuate from FY 2021 through FY 2026, there are enough funds currently in reserves to leave rates unchanged in FY 2022 while still funding budgeted and essential capital investments. The SFPUC is projecting no increases in water supply rates until FY 2023. At that point the SFPUC projects a water supply rate increase of 8% followed by 6% in FY 2024 and 13% in FY 2025. These increases, together with capital needs of the distribution system such as one -time needed reservoir replacements, will place upward pressure on Palo Alto’s water rates. To fund these increasing costs while minimizing rate increases for the City’s water customers, staff Staff: Lisa Bilir and Eric Keniston CITY OF PALO ALTO City of Palo Alto Page 2 expects to recommend the use of the Rate Stabilization Reserve in FY 2024 through FY 2026 to supplement water sales revenues in order to pay for costs. Overall water sales increased approximately 3% during the months affected by the COVID-19 pandemic. Because weather was also dry during the same time period, which also tends to increase water sales, COVID-19-related sales impacts are not able to be determined with specificity. City of Palo Alto Page 3 BACKGROUND Every year staff presents the UAC with Financial Plans fo r the Electric, Gas, Water, and Wastewater Collection Utilities. The Financial Plans recommend rate adjustments required to maintain the financial health of these enterprises. These Financial Plans include a comprehensive overview of the operations of each enterprise, 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. All of the City’s potable water comes from the San Francisco Public Utilities Commission (SFPUC)’s Hetch Hetchy Regional Water System. This same system serves San Francisco and several other Bay Area cities. San Francisco runs the system, but as much as two thirds of the water is used outside of San Francisco by 26 cities, water districts, and private utilities. These agencies, including the City, are frequently referred to as the “wholesale customers” (as compared to the SFPUC’s “retail customers” in San Francisco). The Bay Area Water Supply and Conservation Agency (BAWSCA) represents the wholesale customers and negotiates with the SFPUC on their behalf. BAWSCA also ensures contract compliance through regular review of the SFPUC’s accounting and capital expenditures.1 The Water Utility has two main costs: water supply costs (primarily the cost of water delivered to Palo Alto from the Hetch Hetchy Regional Water System) and the costs of operating the distribution system (the system of pipes, pumps, reservoirs, and other infrastructure that carries water to Palo Alto customers). As discussed in previous years, both cost components have been increasing and are expected to continue to increase. For many years, the largest cost increases have been on the water supply side. This is due primarily to major capital investments the SFPUC has made since 2010, partly due to pressure from wholesale customers. The Water System Improvement Pr ogram (WSIP) is a $4.8 billion capital improvement program, one of the largest in the country, to rehabilitate and seismically strengthen the lower portions of the Hetch Hetchy Regional Water System. One of the goals is to achieve the capability to return to service within 24 hours after a major earthquake. Although much of the work is complete (the program was 98.8% complete as of September 2020), some of the projects are still under construction and bond financing of WSIP projects over the next several years will continue to drive wholesale rates up. The program has greatly improved the resiliency of the Hetch Hetchy Regional Water System but has also led water supply costs to approximately double. CPAU’s operational costs for the water utility have increased at approximately 3% per year for the last five years while capital costs have fluctuated from year to year. This financial plan conservatively projects that capital and operational costs will increase on average at 1 For a video summary of BAWSCA’s activities, see https://vimeo.com/283596665/5619ce2c11 City of Palo Alto Page 4 approximately 3% per year over the next five years. Active use of the CIP Reserve will help keep the fluctuations in capital spending from impacting the Operations Reserve or customer rates. The UAC reviewed preliminary financial forecasts at its December 2, 2020 meeting (UAC Report #11649). DISCUSSION Staff’s annual assessment of the financial position of the City’s water utility is completed to plan for adequate revenue to fund operations, in compliance with the cost of service requirements set forth in the California Constitution (Proposition 218). 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 (COS) methodology described in the 2012 Palo Alto Water Cost of Service & Rate Study, which was updated in 2015, and the 2015 Drought Rate memorandum completed by Raftelis Financial Consultants, which was updated in 2019 and titled “Proposed FY 2020 Water Rates,” (see Attachment Q to staff report 10295.2) Staff proposes no adjustment to water rates in FY 2022. Tables 1 through 3 below illustrate the current rates that would remain unchanged under this financial plan. The rates shown below are in addition to the pass-through commodity rate that is charged to customers based on SFPUC supply charges. The pass-through commodity rate is currently $4.10 per CCF. SFPUC is not anticipated to increase its supply charges in FY 2022. Table 1: Current Water Consumption Charges in $/CCF (Effective July 1, 2019) W-1 (Residential) Volumetric Rates ($/CCF) Tier 1 Rates 2.56 Tier 2 Rates 5.97 W-2 (Construction) Volumetric Rates ($/CCF) Uniform Rate 3.61 W-4 (Commercial) Volumetric Rates ($/CCF) Uniform Rate 3.61 W-7 (Irrigation) Volumetric Rates ($/CCF) Uniform Rate 5.50 2 A cost of service study (COS) is a study using industry-standard techniques to determine how the costs of running the utility should be recovered from its customers; charges to each customer are set in proportion to the cost of serving that customer. City of Palo Alto Page 5 Table 2: Current Monthly Service Charges for W-1, W-4 and W-7 Meter Size Monthly Service Charge ($/month based on meter size) Residential (W-1) Commercial (W-4) and Irrigation (W-7) 5/8” 20.25 17.71 3/4” 20.25 23.67 1” 20.25 35.59 1 ½” 65.40 65.40 2” 101.17 101.17 3” 214.44 214.44 4” 381.37 381.37 6” 780.79 780.79 8” 1,436.57 1,436.57 10” 2,271.20 2,271.20 12” 2,986.60 2,986.60 Table 3: Current Monthly Service Charges for Fire Services (W -3) Meter Size Monthly Service Charge ($/month based on meter size) Current (Effective 7/1/19) 2” $4.17 4” $25.81 6” $74.96 8” $159.74 10” $287.27 12” $464.02 Bill Impact of Proposal There is no bill impact for water utility customers. FY 2022 Financial Plan’s Projected Rate Adjustments for the Next Five Fiscal Years Table 4 shows the projected rate adjustments over the next five years and their impact on the annual median residential water bill for 5/8” customers. These projected rate adjustments include the impact of projected changes to the pass-through commodity rate. City of Palo Alto Page 6 Table 4: Projected Rate Adjustments, FY 2022 to FY 2026 (5/8” meter) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Water Utility 0% 5% 5% 5% 5% Estimated Bill Impact ($/mo)1 $0 $4.52 $4.75 $4.98 $5.23 1) estimated impact on median residential water bill for customers with 5/8” meter, which is currently $90.42. Figures 1 and 2 below illustrate the projected increases in the Water Utility’s costs between FY 2021 and FY 2026. Generator rental costs of approximately $1 million per year are reflected in the Operations costs in Figure 1 and other than that cost item, operations costs increase by inflation. Figure 1: Projected FY 2021 and FY 2026 costs $30 5% % Average Annual % Change "'$25 4% ■ 2021 C 0 :: $20 ~ $15 $10 $5 $0 Water Supply Operations Capital City of Palo Alto Page 7 Figure 2: Percentage of Total Cost Increase From FY 2021 to FY 2026 Attributed to Supply, Capital, and Operations Costs The “Capital” bars on Figure 1 reflect the capital program contributions to the CIP Reserve. Additionally, this financial plan includes one-time transfers to the CIP Reserve to fund seismic reservoir replacement work. There are CIP funds available for projects that were budgeted in FY 2020 and prior years that are carried forward or reappropriated to FY 2021 and will be used to offset the new CIP funding needs. The cost of water is a major driver for the increase in the water utility’s costs (and therefore rates) over the next several years. Wholesale water costs are adopted by the SFPUC, and generally have changed on an annual basis. Costs are projected to increase annually on average by 6% per year from FY 2022 to FY 2026. The SFPUC is currently engaged in a $4.8 billion Water System Improvement Program (WSIP) for regional projects. As of September 30, 2020, 43 of the 52 regional projects were complete or in close-out while 6 of the regional projects were under construction and 1 was in pre-construction.3 This has resulted and will continue to result in large increases in the annual debt service costs assigned to wholesale customers like Palo Alto. After each WSIP project is completed, wholesale customers must start paying the debt service costs within 3 to 4 years. For most of those costs, funded with bond financing, the costs will be 3 First Quarter FY 2020 - 2021 WSIP Regional Quarterly Report,https://www.sfwater.org/modules/showdocument.aspx?documentid=16461 Contribution to FY 2021 to FY 2026 Cost Increases by Source 121 Water Supply ■ Operations □ Capital City of Palo Alto Page 8 paid off over approximately 30 years. The currently estimated WSIP completion date is June 30, 2023, as adopted by the SFPUC in April of 2020. The regional WSIP project remaining in pre-construction is the Alameda Creek Recapture project where permit, design and coordination work is currently ongoing. Current major projects underway are the regional groundwater storage and recovery project and fish passage facilities within the Alameda Creek Watershed. As WSIP projects are completed, SFPUC is pursuing a suite of other capital improvement work; dam safety improvements and Mountain Tunnel repairs are rate increase drivers during the next 10-year timeframe. Future and in- progress construction work will require bond funding, and the SFPUC’s financial plans show debt service cost for the water enterprise growing by 32% between FY 2021 and FY 2026, and by 40% by FY 2028.4 Initial wholesale rate increase projections are 6% per year on average through FY 2026 to cover increasing costs, primarily debt service from ongoing capital investments. Changes in usage due to drought, or recovery from drought, can make the magnitude of future increases difficult to predict. The SFPUC’s costs to operate the Regional Water System are primarily fixed costs, so the water rate charged to wholesale customers like the City of Palo Alto is highly dependent on usage by all users of the Regional Wat er System. The City’s FY 2022 Water Utility Financial Plan assumes that, while the drought has ended and usage has increased, consumption will not fully return to pre -drought levels. This assumption is based on CPAU’s experience following past droughts. The SFPUC is currently working on determining the wholesale revenue requirement and rate proposals for FY 2022; the long-range wholesale costs projections are subject to change. Because wholesale sales of water by the SFPUC in recent years were higher than projected during the drought and during the recent months impacted by the COVID -19 pandemic, the SFPUC has been accumulating funds in its Wholesale Customer Balancing Account. The SFPUC will use these funds to offset rate increases. The SFPUC does not ant icipate needing to raise wholesale rates until FY 2023. Additionally, operations costs are projected to increase by around 4% overall over the forecast period. These increases are primarily due to inflation assumptions as well as generator rental expenses of $1 million annually beginning during this time period. There remains some uncertainty in the forecasts of capital costs for the water utility in coming years. Water main replacement costs have risen substantially in recent years. The regional and even national focus on infrastructure improvement has created labor shortages, leading to higher bid prices than were seen in the past. Several factors go into main replacement cost, such as location as well as the length of main segments. Consistent with the FY 2021 Financial Plan, this plan includes larger main replacement construction projects every other year instead 4 FY 2018-19 & FY 2019-20 Adopted SFPUC Budget, https://sfwater.org/modules/showdocument.aspx?documentid=13147 City of Palo Alto Page 9 of smaller projects annually. This main replacement schedule will allow CPAU to meet its main replacement needs and addresses challenges in th e current construction market while optimizing current staffing resources. Larger main replacement construction projects every other year are anticipated to attract more contractors to bid on the larger projects. Council has approved a design/build contract for the Corte Madera reservoir replacement and the project is expected to be completed in FY 2021. Based on the cost of the Corte Madera reservoir replacement, the cost estimates increased for the replacement of Dahl and Park reservoirs in FY 2023 and FY 2026 by $3.5 million for each reservoir relative to the FY 2021 adopted budget levels. Although the revised main replacement schedule is important for the reasons described above, fluctuations in capital expenditures can lead to fluctuations in customer rates. To promote rate stability and provide continuity in water expenditure levels, this plan continues with the approach established in the FY 2021 Financial Plan for consistent annual contributions from the Operations Reserve to the CIP Reserve. In FY 2022, the amount proposed for the Capital Program Contribution is $8.24 million. CIP projects will then be charged to the CIP Reserve, which will experience fluctuations in its balance as a result of projects carried over from past years (but already funded) and as a result of the two-year project cycle. This should enable rate increases to remain relatively smooth. Figure 3 below shows the projected CIP Reserve balances under this Financial Plan. Table 5 below shows the planned capital spending in row 12 fluctuating from year to year with the staggered main replacement schedule and shows the stable capital program contributions to the CIP Reserve in rows 9 and 10. The Operations Reserve is shown as combined with unassigned funds, because when the Operations Reserve reaches its maximum level, any additional funds are included in the Unassigned Reserve, in accordance with the Water Utility Reserve Management Practices. The attached Financial Plan includes a plan to assign these funds to capital investment purposes. Figure 4 shows the amount of funds that are considered unassigned during the forecast period, together with reserve balance changes for each reserve from FY 2020 and projected through FY 2026. City of Palo Alto Page 10 Figure 3: Projected Capital Reserve Balances FY 2021 to FY 2026 Figure 4: Actual Reserve Levels for FY 2020 and Projections through FY 2026 City of Palo Alto Page 11 Table 5: Operations & Unassigned, Rate Stabilization and CIP Reserves Starting and Ending Balances, Revenues, Transfers To/(From) Reserves, Capital Program Contribution To/(From) Reserves, and Operations Reserve Guideline Levels Projected for FY 2021 to FY 2026 ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Starting Balance (1) Operations/Unassigned 19,841 20,684 14,353 9,252 11,718 11,585 (2) Rate Stabilization 9,069 9,069 9,069 9,069 5,000 3,000 (3) CIP 5,726 10,310 10,608 11,615 7,274 11,122 Revenues (4) Total Revenue 49,015 48,563 50,281 52,632 55,470 57,678 (5) Transfers In 249 254 259 264 269 275 Transfers (6) Operations/Unassigned - (5,000) (3,500) 4,069 2,000 (500) (7) Rate Stabilization - - - (4,069) (2,000) (3,000) (8) CIP - 5,000 3,500 - - 3,500 Capital Program Contribution (9) Operations/Unassigned (8,000) (8,240) (8,487) (8,742) (9,004) (9,274) (10) CIP 8,000 8,240 8,487 8,742 9,004 9,274 Expenses (11) Total Expenses other than CIP (39,936) (41,414) (43,150) (44,634) (47,733) (48,935) (12) Planned CIP (3,416) (12,942) (10,980) (13,083) (5,156) (21,295) (13) Transfers Out (484) (494) (504) (1,124) (1,134) (1,145) Ending Balance (1)+(4)+(5)+(6) +(9)+(11)+(13) Operations/Unassigned 20,684 14,353 9,252 11,718 11,585 9,684 (2)+(7) Rate Stabilization 9,069 9,069 9,069 5,000 3,000 - (3)+(8)+(10)+ (12)* CIP 10,310 10,608 11,615 7,274 11,122 2,602 Operations Reserve Guideline Levels (14) Minimum 6,644 6,889 7,176 7,522 8,033 8,232 (15) Maximum 13,289 13,778 14,352 15,044 16,066 16,464 * Planned CIP (item 12) is reflected as an expense in the CIP Reserve and does not include CIP funded through reappropriations or commitments from prior years. Capital Projects & Reserve Higher bid cost and delays in project schedules resulted in a deferment of main replacement projects in FY 2017 through FY 2020, temporarily lowering CIP expenditures. This resulted in the Operations Reserve being filled to the maximum guideline level. The capital budget includes one-time seismic water system upgrades and/or replacements for the Corte Madera, Park and Dahl reservoirs to improve earthquake resistance. This work will improve protection from water loss at these reservoirs in a seismic event. This plan updates the transfer proposals due to the project cost increases. Specifically, the proposed transfers from the Opera tions Reserve to the CIP Reserve, in addition to the $3 million transfer that occurred in FY 2020, are $5 million in FY City of Palo Alto Page 12 2022, $3.5 million in FY 2023, and $3.5 million in FY 2026 (see line 8 in Table 5). This Financial plan includes the request for up to the $5 million in FY 2022; staff will request Council approval for the remaining transfers in future Financial Plans once the year -end FY 2021 reserve balances are known. The Operations Reserve levels are projected to be sufficient to support this funding need. At year end FY 2020, an estimated nearly $6 million was considered unassigned (above the maximum guideline level in the Operations Reserve); the intended use of these funds is for the reservoir replacements. Table 5 above shows the anticipated CIP Reserve transfers in FY 2021 through FY 2026. There is also approximately $11.3 million in CIP that was budgeted in 2020 or prior years that is reappropriated or carried forward from previous years and is currently in the CIP Reappropriations and CIP Commitments Reserves. See Appendix B of the Water Utility Financial Plan for detailed information. Rate Stabilization Reserve The Rate Stabilization Reserve is projected to be used to buffer rate increases needed to pay for a series of large wholesale supply rate increases that are anticipated to begin annually in FY 2023. In June 2020, Council approved a transfer of $5 million from the Operations Reserve to the Rate Stabilization Reserve, bringing the balance in the reserve to $9.07 million. The FY 2021 Financial Plan also contemplated a $3.5 million additional transfer from the Operations Reserve to the Rate Stabilization Reserve in FY 2021. However, the cost of one-time reservoir replacements has increased and instead of transferring additional funds to the Ra te Stabilization Reserve, this plan recommends transferring an additional $5 million from the Operations Reserve to the CIP Reserve to fund reservoir replacement work. Depending upon the reserve balances and updated cost projections available at year end F Y 2021, the next financial plan will recommend further transfers. Beginning in FY 2024, CPAU expects to transfer funds annually from the Rate Stabilization Reserve to the Operations Reserve to limit water rate increases. The use of the Rate Stabilization Reserve balances in this way, together with the cost and revenue projections in this Financial Plan is expected to allow CPAU water rates to increase by 5% or less annually over the next five years. This Financial Plan projects that the Rate Stabilization Reserve will be exhausted by the end of FY 2026. Water Bill Comparison with Surrounding Cities Table 6 compares water bills for residential customers to those in surrounding communities as of January 2021 (under current the City’s current water rates). Palo Alto customers have some of the highest monthly bills of the group, although bills for smaller water users are lower than in some surrounding communities. It is unclear at this time what water rate changes may be implemented in surrounding communities for FY 2022. The average calculated in the following table is the mean of the six surrounding communities listed. These communities are the same City of Palo Alto Page 13 six that Palo Alto compares itself to in the annual budget across Water, Wastewater, Gas and Electric industries. Table 6: Residential Monthly Water Bill Comparison Usage (CCF/month) Residential monthly bill comparison ($/month)* As of January, 2021 Palo Alto Menlo Park Mountain View Hayward Redwood City Santa Clara Los Altos Average of Surrounding Communities 4 $46.89 $52.42 $38.34 $39.20 $54.04 $44.62 $42.99 $45.27 (Winter median) 7 $70.28 $77.50 $59.37 $60.62 $76.09 $63.91 $60.84 $66.39 (Annual median) 9 $90.42 $94.23 $73.39 $74.90 $90.79 $76.77 $72.73 $80.47 (Summer median) 14 $140.77 $136.31 $108.44 $112.51 $138.94 $108.92 $101.62 $117.79 25 $251.54 $229.06 $227.65 $205.02 $267.39 $179.65 $169.20 $212.99 *Based on the FY 2013 BAWSCA survey, the fraction of SFPUC as the source of potable water supply was 100% for Palo Alto, 95% for Menlo Park, 100% for Redwood City, 87% for Mountain View, 10% for Santa Clara and 100% for Hayward. Los Altos does not receive water supply from SFPUC. Changes from Last Year’s Financial Forecast Table 7 compares current rate projections to those projected in the Financial Pl ans from the last two years. The proposed rate changes are the same as the FY 2021 Financial Plan. Table 7: Projected Water Rate Trajectory for FY 2022 to FY 2026 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current 0% 5% 5% 5% 5% Last year (FY 2021 Financial Plan) 0% 5% 5% 5% - Two years ago (FY 2020 Financial Plan) 3% 6% 6% - - Table 8 shows the proposed water rate increases broken out into the needed increases to commodity revenues, to cover the costs of purchasing water from SFPUC, and the distribution revenue increases to pay for the upkeep of Palo Alto’s water distribution system. City of Palo Alto Page 14 Table 8: Proposed Commodity and Distribution Water Revenue Changes FY 2022 to FY 2026 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Commodity Revenue (SFPUC Purchases) 0% 8% 6% 12%* 6% Distribution Revenue 0% 3% 4% 0% 4% Total Revenue 0% 5% 5% 5% 5% *SFPUC’s projected increase in FY 2025 is 13%, however, this financial plan uses rate stabilization reserves and holds distribution revenu e increases to 0% in FY 2025 to hold the overall forecasted impact to customers at no more than 5% annually. This plan uses the Rate Stabilization Reserve and CIP Reserve to stabilize rates while anticipating a series of large wholesale water rate increases and funding needed water CIP budgets. NEXT STEPS The Finance Committee will review the FY 2022 Water Financial Plan in March or April 2021. Assuming the Finance Committee supports staff’s recommendation, no notification of rate increases would be necessary because the current rates would not increase. RESOURCE IMPACT Normal year sales revenues for the Water Utility will not be impacted by this proposal to maintain the current rates for FY 2022. The FY 2022 Budget is being developed concurrent with these rates and, depending on the final rates, adjustments to the budget may be necessary later. See the attached FY 2022 Water Financial Plan for a more comprehensive overview of projected cost and revenue changes for the next five years. POLICY IMPLICATIONS Maintaining the current rates for FY 2022 is consistent with Reserve Management Practices and exemptions included in the Financial Plans and described above, and the rates were developed using a cost-of-service study and methodology consistent with the cost of service requirements of Proposition 218. ENVIRONMENTAL REVIEW The UAC’s review and recommendation to Council on the FY 2022 Water Financial Plan and rate adjustments does not meet the definition of a project requiring California Environmental Quality Act (CEQA) review under Public Resources Code Section 21065 thus no environmental review is required. Attachments: • Attachment A: Resolution • Attachment B: Water Financial Plan 2022 • Attachment C: Presentation Attachment A 6055486 * NOT YET APPROVED * Resolution No.__________ Resolution of the Council of the City of Palo Alto Approving the FY 2022 Water 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. The City 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 2022 Water Utility Financial Plan. SECTION 2. The Council hereby approves a transfer from the Operations Reserve to the Capital Improvement Projects Reserve of up to $13,240,000 in FY 2022 as described in the FY 2022 Water Utility Financial Plan. Annual capital program contributions beyond FY 2022 will be approved by Resolution annually. // // // // // // // // Attachment A 6055486 // 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 CEQA Guidelines Section 15378(b)(5), because it is an administrative governmental activity which will not cause a direct or indirect physical change in the environment, and therefore, no environmental review is required. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: ________________________________ ________________________________ City Clerk Mayor APPROVED AS TO FORM: APPROVED: ________________________________ ________________________________ Assistant City Attorney City Manager ________________________________ Director of Utilities ________________________________ Director of Administrative Services WATER UTILITY FINANCIAL PLAN March 2021 1 | Page FY 2022 WATER UTILITY FINANCIAL PLAN FY 2022 TO FY 2026 Attachment B WATER UTILITY FINANCIAL PLAN March 2021 2 | Page FY 2022 WATER UTILITY FINANCIAL PLAN FY 2022 TO FY 2026 TABLE OF CONTENTS Section 1: Definitions and Abbreviations................................................................................ 4 Section 2: Executive Summary and Recommendations ........................................................... 4 Section 2A: Overview of Financial Position .................................................................................. 4 Section 2B: Summary of Proposed Actions .................................................................................. 7 Section 3: Detail of FY 2022 Rate and Reserves Proposals ....................................................... 8 Section 3A: Rate Design ............................................................................................................... 8 Section 3B: Current and Proposed Rates ..................................................................................... 8 Section 3C: Proposed Reserve Transfers .................................................................................... 11 Section 4: Utility Overview .................................................................................................. 12 Section 4A: Water Utility History ............................................................................................... 13 Section 4B: Customer Base ........................................................................................................ 14 Section 4C: Distribution System ................................................................................................. 14 Section 4D: Cost Structure and Revenue Sources ...................................................................... 14 Section 4E: Reserves Structure ................................................................................................... 15 Section 4F: Competitiveness ...................................................................................................... 15 Section 5: Utility Financial Projections ................................................................................. 16 Section 5A: Load Forecast .......................................................................................................... 16 Section 5B: FY 2016 to FY 2020 Cost and Revenue Trends ........................................................ 18 Section 5C: FY 2020 Results ....................................................................................................... 19 Section 5D: FY 2021 Projections ................................................................................................ 19 Section 5E: FY 2022 – FY 2026 Projections ................................................................................ 20 Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 23 Section 5G: Alternate scenario .................................................................................................. 24 Section 5H: Long-Term Outlook ................................................................................................. 24 WATER UTILITY FINANCIAL PLAN March 2021 3 | Page Section 6: Details and Assumptions ..................................................................................... 25 Section 6A: Water Purchase Costs ............................................................................................. 25 Section 6B: Operations .............................................................................................................. 27 Section 6C: Capital Improvement Program (CIP) ....................................................................... 28 Section 6D: Debt Service ............................................................................................................ 33 Section 6E: Other Revenues ....................................................................................................... 34 Section 6F: Sales Revenues ........................................................................................................ 35 Section 7: Communications Plan .......................................................................................... 35 Appendices ......................................................................................................................... 35 Appendix A: Water Utility Financial Forecast Detail ................................................................. 37 Appendix B: Water Utility Capital Improvement Program (CIP) Detail ..................................... 39 Appendix C: Water Utility Reserves Management Practices ..................................................... 40 Appendix D: Description of Water Utility Operational Activities ............................................... 43 Appendix E: Sample of Water Utility Outreach Communications ............................................. 44 WATER UTILITY FINANCIAL PLAN March 2021 4 | Page SECTION 1 : DEFINITIONS AND ABBREVIATIONS BAWSCA Bay Area Water Supply and Conservation Agency CCF The standard unit of measurement for water delivered to water customers, equal to one hundred cubic feet, or roughly 748 gallons. CIP Capital Improvement Program CPAU City of Palo Alto Utilities Department O&M Operations and Maintenance RFC Raftelis Financial Consultants, Inc. SFPUC San Francisco Public Utilities Commission SFWD San Francisco Water Department UAC Utilities Advisory Commission WSIP The SFPUC’s Water System Improvement Program to seismically strengthen the transmission lines of the Hetch Hetchy Regional Water System. SECTION 2 : EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Water Utility for FY 2022 through FY 2026. This Financial Plan provides for revenues to cover the costs of operating the utility safely over that period 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 FINANCIAL POSITION Staff expects overall costs in the Water Utility to rise on average by about 4% per year from fiscal year (FY) 2022 to 2026. Operations cost projections rise on average by about 3% annually through the projection period. Water supply costs are based on current SFPUC projections and are the largest individual component of the utility’s costs. The cost of the City’s SFPUC water supply is increasing over the forecast period due to increasing debt service for a series of major capital projects on the Hetch Hetchy Regional Water System. However, the SFPUC’s water supply rates will remain relatively flat through FY 2022 as SFPUC returns to customers reserves it accumulated in prior years, with rates rising steeply after FY 2022. See Section 6A: Water Purchase Costs for more information. Capital costs were lower than budgeted in FY 2020. In FY 2021 and 2022 many of the budgeted capital projects that were deferred from previous years are anticipated to be completed and reserve funds are available for the majority of those costs. The water utility plans for a main replacement construction project every other year. Actual capital costs vary from year to year, however, this financial plan continues with a stable annual capital contribution from the Operations Reserve to the Capital Improvement Program Reserve (CIP Reserve). This contribution began in FY 2021 with the adoption of the FY 2021 Water Financial Plan and it promotes rate stability and continuity in water expenditure levels. Section 6C: Capital Improvement Program (CIP) provides more detail. Table 1 below shows the costs for the Water Utility from FY 2020 through FY 2026. The “CIP” row in Table 1 includes capital funding needed in FY 2020 and planned contributions from rates to the CIP Reserve for FY 2021 through FY 2026 and does not include the additional one-time transfers from the Operations Reserve to the CIP Reserve shown in Table WATER UTILITY FINANCIAL PLAN March 2021 5 | Page 4. This differs from planned CIP which is shown in line 12 of Table 4 and is reflected as an expense in the CIP Reserve. Table 1: Expenses for FY 2020 to FY 2026 (Thousand $’s) Expenses ($000) FY 2020 (act.) FY 2021 (est.) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Water Purchases 21,773 21,847 21,592 22,867 23,839 26,412 27,266 Operations 18,836 18,573 20,316 20,787 21,918 22,456 22,814 CIP 3,265 8,000 8,240 8,487 8,742 9,004 9,274 TOTAL 43,875 48,420 50,148 52,141 54,500 57,872 59,354 This proposed Financial Plan projects that the Water Utility will need the rate increases shown in Table 2 in order for revenues to cover costs and reserves to remain within guideline levels. Water supply costs are projected to increase beginning in FY 2023, water sales are projected to decline somewhat, and little or no increase is expected in non-sales revenue (e.g., interest, connection fees). Overall water sales increased approximately 3% during the months affected by the pandemic. Because weather was also dry during the same time period, which also tends to increase water sales, COVID-19-related sales impacts are not able to be determined with specificity. Section 5E: FY 2022 – FY 2026 Projections contains additional detail. Table 2 also shows rate projections from the last two Financial Plans for FY 2020 and FY 2021; the proposed rate increases have not changed from the FY 2021 Financial Plan, however they are lower than the proposed rate increases in the FY 2020 Plan. Table 2: Proposed and Projected Water Revenue Changes for FY 2022 to FY 2026 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current 0% 5% 5% 5% 5% FY 2021 Plan 0% 5% 5% 5% - FY 2020 Plan 3% 6% 6% - - Table 3 shows the proposed water rate increases broken out into the needed increases to commodity revenues, to cover the costs of purchasing water from SFPUC and separately the distribution revenue increases to pay for the upkeep of Palo Alto’s water distribution system. Table 3: Proposed Commodity and Distribution Water Revenue Changes FY 2022 to FY 2026 Projection FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Commodity Revenue (SFPUC Purchases) 0% 8% 6% 12%* 6% Distribution Revenue 0% 3% 4% 0% 4% Total Revenue 0% 5% 5% 5% 5% *SFPUC’s projected water supply rate increase in FY 2025 is 13%, however, this Financial Plan uses the Rate Stabilization Reserves and holds distribution revenue increases to 0% in FY 2025 to forecast an overall impact to customers of no more than 5% annually. WATER UTILITY FINANCIAL PLAN March 2021 6 | Page The Water Utility’s Rate Stabilization Reserve can be used to smooth rate increases over several years. In June 2020, Council approved a transfer of $5 million from the Operations Reserve to the Rate Stabilization Reserve, bringing the balance in the reserve to $9.07 million at FY 2020 year end. The use of the Rate Stabilization Reserve, together with the cost and revenue projections in this Financial Plan allow projected CPAU water rates to increase by 5% or less annually over the next five years. This Financial Plan projects that the Rate Stabilization Reserve will be exhausted by the end of FY 2026. The Water Utility also has a Capital Improvement Program (CIP) Reserve that is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. In FY 2021, the water utility began funding the CIP Reserve with an annual capital program contribution as well as one- time transfers for one-time reservoir upgrade projects. The annual capital program contribution began at a level of $8 million in FY 2021 and this plan proposes $8.24 million in FY 2022 based upon an estimate of the amount of CIP work there is each year, spread out over the forecast period. Having these funds in place will address uneven annual funding associated with ongoing CIP projects, and will be a source for one-time or immediately needed projects. Figure 11 shows the projected CIP Reserve balances and guideline levels for FY 2022 through FY 2026. This plan updates the transfer proposals due to the project cost increases for reservoir replacements. Specifically, the proposed transfers from the Operations Reserve to the CIP Reserve, in addition to the $3 million transfer that occurred in FY 2020, are $5 million in FY 2022, $3.5 million in FY 2023, and $3.5 million in FY 2026 (see line 8 in Table 4). Staff will request Council approval for the transfers beyond FY 2022 in future Financial Plans once the year-end FY 2021 reserve balances are known. At year end FY 2020, an estimated nearly $6 million was considered unassigned (above the maximum guideline level in the Operations Reserve); the intended use of these funds is for the reservoir replacements. Higher bid cost and delays in project schedules resulted in a deferment of main replacement projects in FY 2017 through FY 2019, temporarily lowering costs. This resulted in the Operations Reserve being filled to the maximum guideline level, with surplus reserves available to phase in rate increases more slowly over the forecast period. The maximum guideline level for the Operations Reserve equals 120 days of operations and maintenance and commodity expense. Table 4 shows the starting and ending balances for the Operations & Unassigned Reserves combined, Rate Stabilization Reserve, and CIP Reserve, minimum and maximum Operations Reserve guideline levels and projected reserve transfers over the forecast period. See Section 3D: Proposed Reserve Transfers for more details. WATER UTILITY FINANCIAL PLAN March 2021 7 | Page Table 4: Operations & Unassigned, Rate Stabilization and CIP Reserves Starting and Ending Balances, Revenues, Transfers To/(From) Reserves and Capital Program Contribution To/(From) Reserves Projected for FY 2021 to FY 2026 ($000) FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Starting Balance (1) Operations/Unassigned 19,841 20,684 14,353 9,252 11,718 11,585 (2) Rate Stabilization 9,069 9,069 9,069 9,069 5,000 3,000 (3) CIP 5,726 10,310 10,608 11,615 7,274 11,122 Revenues (4) Total Revenue 49,015 48,563 50,281 52,632 55,470 57,678 (5) Transfers In 249 254 259 264 269 275 Transfers (6) Operations/Unassigned - (5,000) (3,500) 4,069 2,000 (500) (7) Rate Stabilization - - - (4,069) (2,000) (3,000) (8) CIP - 5,000 3,500 - - 3,500 Capital Program Contribution (9) Operations/Unassigned (8,000) (8,240) (8,487) (8,742) (9,004) (9,274) (10) CIP 8,000 8,240 8,487 8,742 9,004 9,274 Expenses (11) Total Expenses other than CIP (39,936) (41,414) (43,150) (44,634) (47,733) (48,935) (12) Planned CIP (3,416) (12,942) (10,980) (13,083) (5,156) (21,295) (13) Transfers Out (484) (494) (504) (1,124) (1,134) (1,145) Ending Balance (1)+(4)+(5)+(6) +(9)+(11)+(13) Operations/Unassigned 20,684 14,353 9,252 11,718 11,585 9,684 (2)+(7) Rate Stabilization 9,069 9,069 9,069 5,000 3,000 - (3)+(8)+(10)+ (12)* CIP 10,310 10,608 11,615 7,274 11,122 2,602 Operations Reserve Guideline Levels (14) Minimum 6,644 6,889 7,176 7,522 8,033 8,232 (15) Maximum 13,289 13,778 14,352 15,044 16,066 16,464 * Planned CIP (item 12) is reflected as an expense in the CIP Reserve and does not include CIP funded through reappropriations or commitments SECTION 2 B : SUMMARY OF PROPOSED ACTIONS Staff proposes the following action for the Water Utility in FY 2022: 1. A transfer of up to $13.24 million from the Operations Reserve to the CIP Reserve in FY 2022. See Section 6C: Capital Improvement Program (CIP) for more details. WATER UTILITY FINANCIAL PLAN March 2021 8 | Page SECTION 3 : DETAIL OF FY 2022 RATE AND RESERVES PROPOSALS SECTION 3 A : RATE DESIGN The Water Utility’s rates are evaluated and implemented in compliance with the cost of service requirements and procedural rules set forth in Article XIII D of the California Constitution (Proposition 218) and applicable statutory law. The City structured current rates based on staff’s assessment of the financial position of the Water Utility, and updated current rates using the methodology from the March 2012 Palo Alto Water Cost of Service & Rate Study by Raftelis Financial Consultants, Inc. (RFC) (Staff Report 2676), RFC’s 2015 Memorandum: Proposed Water Rates updating the 2012 Study and analyzing drought rates (Staff Report 5951), as well as RFC’s 2019 Memorandum updating the 2012 study (Staff Report 10295). Staff plans to update the cost of service study in 1 to 2 years, unless any major changes occur to the utility’s operations or customer base that would necessitate an earlier study. Before conducting any new cost of service study, staff will review current rates and the scope of the study with the Utilities Advisory Commission (UAC) and Council to determine the City’s policy priorities. SECTION 3 B : CURRENT AND PROPOSED RATES The current rates and surcharges became effective on July 1, 2019. CPAU has five rate schedules: separately metered residential customers (W-1), commercial and master-metered multi-family residential customers (W-4), irrigation-only services (W-7), services to fire sprinkler systems in buildings and private hydrants (W-3), and service to fire hydrant rental meters used for construction (W-2). All customers pay a monthly service charge based on the size of their inlet meter. This charge represents meter reading, billing, and other customer service costs, and also the cost of maintaining the capability to deliver a peak flow for that customer based on their meter size. All customers are also charged for each CCF (one hundred cubic feet) of water used. Separately metered residential customers are charged on a tiered basis, with the first 0.2 CCF per day (6 CCF for a 30 day billing period) charged at the first tier price per CCF, and all additional units charged a higher tier price per CCF. Commercial customers, including most multi-family customers, pay a uniform price for each CCF used. A separate rate per CCF exists for separately metered irrigation service. For July 1, 2021, staff is proposing no rate increase. Water rates are composed of two general types of costs: commodity and distribution. Commodity costs are mainly volumetric in nature and charged by the San Francisco Public Utilities Commission (SFPUC). In May 2020, the SFPUC provided a rate notice letter that their W-25 wholesale rate for agencies with long-term contracts would remain at $4.10/CCF in FY 2021 and also estimated it would remain at $4.10/CCF in FY 2022. The SFPUC will not determine its final wholesale customer rate for FY 2022 until May or June, 2021. If SFPUC’s final rate for FY 2022 does increase, the City must notify customers 30 days in advance of the pass-through rate increase. The May 2020 rate notice contemplates no rate increase until FY 2024 when 15.2% rate increase would be needed as well as an additional 11.1% increase in FY 2025. However, this assumes that the wholesale customer balancing account is fully drained before any wholesale customer rate increases occur. SFPUC also issued a 10-year WATER UTILITY FINANCIAL PLAN March 2021 9 | Page financial plan in February 2020 that illustrates a possible rate trajectory with generally smaller annual rate increases that begin in FY 2023 instead of FY 2024, which assumes the use of the balancing account to smooth the needed rate increases. This Financial Plan uses the SFPUC’s 10- year financial plan rate trajectory. Distribution rates cover all the costs to deliver water within the City, such as operations, maintenance, metering, billing, and capital improvements. Prior to 2021, the distribution costs would fluctuate depending on capital improvement spending. However, in June 2020 the Council approved a steady amount of funding to the capital reserve beginning in FY 2021 and the amount to be transferred to the CIP Reserve is approved annually by Council. With this change, the CIP Reserve now reflects actual fluctuations in CIP expenditures (money spent on actual projects in a given year). Previously, CIP expenditures were reflected in the Operations Reserve. Table 4 (row 12) shows planned CIP expenditures and the CIP Reserve balance is calculated by taking the starting balance for the CIP Reserve (row 3), adding the one-time transfers (row 8) and capital program contributions (row 10) and subtracting planned CIP expenditures (row 12). Section 5E: FY 2022 – FY 2026 Projections contains a more detailed description of this change. In this way, although CIP expenditures fluctuate from year to year, the capital program contribution to the CIP reserve is projected to remain fairly constant over the next five years, increasing by 3% per year on average. The exception to this is the one-time reservoir replacement costs that will be funded through one-time transfers from the Operations Reserve. More detail regarding reserve transfers is in Section 3C: Proposed Reserve Transfers. Operations costs are discussed in Section 6B: Operations, below. Customers have a separate commodity rate for purchased water from SFPUC relative to the rest of the distribution-related portion of the volumetric rates. This charge passes-through future SFPUC rate increases to customers. All customers will pay this separate commodity cost for each unit of water in addition to the volumetric rate that is applicable for their customer class. The rates shown below are in addition to the pass-through commodity rate that is charged to customers based on SFPUC supply charges. The pass-through commodity rate is currently $4.10 per CCF. SFPUC is not anticipated to increase its supply charges in FY 2022. This automatically adjusting pass-through charge is effective July 1, 2019 through July 1, 2024 pursuant to Resolution 9844 “Resolution of the Council of the City of Palo Alto Adopting a Water Rate Increase and Amending Utility Rate Schedules W-1, W-2, W-3, W-4 and W-7, June 17, 2019.” WATER UTILITY FINANCIAL PLAN March 2021 10 | Page Table 5 shows the current consumption charges, which, like the rates in Table 6 and Table 7, are not proposed to change for FY 2022. Table 5: Water Consumption Charges ($/CCF) W-1 (Residential) Volumetric Rates ($/CCF) Tier 1 Rates 2.56 Tier 2 Rates 5.97 W-2 (Construction) Volumetric Rates ($/CCF) Uniform Rate 3.61 W-4 (Commercial) Volumetric Rates ($/CCF) Uniform Rate 3.61 W-7 (Irrigation) Volumetric Rates ($/CCF) Uniform Rate 5.50 WATER UTILITY FINANCIAL PLAN March 2021 11 | Page Table 6 shows the current monthly service charges for rate schedule W-1, W-4 and W-7. Table 6: Current Monthly Service Charges for W-1, W-4 and W-7 Meter Size Monthly Service Charge ($/month based on meter size) Residential (W-1) Commercial (W-4) and Irrigation (W-7) 5/8” 20.25 17.71 3/4” 20.25 23.67 1” 20.25 35.59 1 ½” 65.40 65.40 2” 101.17 101.17 3” 214.44 214.44 4” 381.37 381.37 6” 780.79 780.79 8” 1,436.57 1,436.57 10” 2,271.20 2,271.20 12” 2,986.60 2,986.60 Table 7 shows the current monthly service charges for rate schedule W-3 Table 7: Current Monthly Service Charges for Fire Services (W-3) Meter Size Monthly Service Charge ($/month based on meter size) Current (7/1/19) 2” $4.17 4” $25.81 6” $74.96 8” $159.74 10” $287.27 12” $464.02 SECTION 3 C : PROPOSED RESERVE TRANSFERS In the FY 2021 Financial Plan, Council approved a $5 million transfer from the Operations Reserve to the Rate Stabilization Reserve in FY 2020, which brought the balance in the Rate Stabilization Reserve to $9.07 at year-end FY 2020. The Rate Stabilization Reserve will be used to offset the costs of a series of large wholesale supply rate increases that are anticipated to begin annually in FY 2023. The use of the Rate Stabilization Reserve in this way allows projected CPAU water rates to increase by 5% or less annually over the next five years. Funds from the Rate Stabilization Reserve will be drawn down annually beginning in FY 2024 to minimize the need for a rate increase triggered by increasing costs. See Table 4 above, row 7, for a summary of the reserve transfers into and out of the Rate Stabilization Reserve. SFPUC projects wholesale rate increases WATER UTILITY FINANCIAL PLAN March 2021 12 | Page from $4.10 per CCF currently to $4.43 per CCF in FY 2023, $4.70 per CCF in FY 2024, and $5.33 per CCF in FY 2025 with annual increases continuing beyond FY 2025. The Water Utility Reserves Management Practices state that if there are funds in the Rate Stabilization Reserve at the end of any fiscal year, any subsequent Water Utility Financial Plan must result in the withdrawal of all funds from this reserve by the end of the Financial Planning Period. This Financial Plan recommends withdrawing the funds from the Rate Stabilization Reserve for the purpose of rate stabilization in FY 2024 through FY 2026, the end of the Financial Planning Period. In the FY 2021 Financial Plan, Council approved an $8 million capital program contribution to the CIP Reserve from the Operations Reserve in FY 2021. This amount is an estimate of the amount of CIP work there is in a given year, spread out over the forecast period. This Financial Plan recommends an $8.24 million capital program contribution to the CIP Reserve in FY 2022. Table 4 above shows the proposed capital program contributions in row 10. Having these funds in place will address uneven annual funding associated with ongoing CIP projects, and will be a source for one-time or immediately needed projects. Additionally, in the FY 2021 Financial Plan, Council approved one-time transfers from the Operations Reserve to the CIP Reserve to fund reservoir replacement costs for the remaining Corte Madera reservoir replacement costs and the Dahl and Park reservoir replacement costs. These one-time transfers totaled $8 million ($3 million in FY 2020, $1.5 million in FY 2021 and $3.5 million in FY 2022). The $3 million transfer in FY 2020 was completed and brought the balance in the CIP Reserve at year end FY 2020 to $5.726 million. Based upon the costs for the Corte Madera work, staff estimates that the Park and Dahl reservoirs will each cost $3.5 million more than anticipated last year. This Financial Plan recommends adding $3.5 million in one-time transfers in FY 2023 and FY 2026, the years when construction is planned for the remaining two tank replacements. Based on the projected CIP Reserve balance at year end FY 2021 being at the maximum guideline level, staff recommends waiting until FY 2022 to transfer the $5 million in one-time transfers (instead of $1.5 million in FY 2021 and $3.5 million in FY 2022) in order to re- evaluate once the reserve balances are known at the end of FY 2021. Projected one-time spending needs for reservoir replacement are shown in Appendix B on the line labeled “WS-09000 Seismic Water System”. The one-time transfers to the CIP Reserve to pay for the reservoir replacement costs allows the CIP Reserve to remaining within guideline levels and sufficiently fund budgeted CIP as fluctuating annual amounts of capital investment occur going forward. Table 4 shows the proposed capital program contributions in row 8. In addition, the funds will help to stabilize rate fluctuations for customers that may otherwise result from fluctuations in capital spending. Section 4E: Reserves Structure and Appendix A: Water Utility Financial Forecast Detail shows details of reserves levels. SECTION 4 : UTILITY OVERVIEW WATER UTILITY FINANCIAL PLAN March 2021 13 | Page This section provides an overview of the utility and its operations. It provides general background information and helps readers better understand the forecasts in Section 5: Utility Financial Projections and Section 6: Details and Assumptions. SECTION 4 A : WATER UTILITY HISTORY The Water Utility was established on May 9, 1896, two years after the city was incorporated. Voters of the 750-person community approved a $40,000 bond to buy local, private water companies who 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. Palo Alto began receiving water from the San Francisco Water Department (SFWD) in 1937 to supplement these sources. A 1950 engineering report noted, “the capricious alternation of well waters and the San Francisco Water Department water…has made satisfactory service to the average customer practically impossible”. By 1950, only eight wells were still in operation. Despite this, groundwater production increased in the 1950’s leading to lower groundwater tables and water quality concerns. In 1962, a survey of water softening costs to CPAU customers determined that CPAU should purchase 100% of its water supply needs from the SFWD. CPAU signed a 20-year contract with SFWD, and CPAU’s wells were placed in standby condition. The SFWD later became known as the SFPUC. Since 1962 (except for some very short periods) CPAU’s entire supply of potable water has come from the SFPUC. As the city grew, so did the number of mains in the water system, while existing sections of the system continued to age. In the mid-1980s, the number of breaks in cast iron mains installed during the 1940s and earlier started to accelerate. In FY 1994, to combat deterioration of older sections of the system, CPAU performed an analysis of cost-effective system improvements and increased the rate of main replacement from one mile per year to three. CPAU began a plan to replace 75 miles of deficient mains within 25 years. In 1999, a study of system reliability concluded that the distribution system needed major upgrades to provide adequate water supply during a natural disaster. This ultimately resulted in the $40 million Emergency Water Supply and Storage Project, completed in 2013, which involved a new underground reservoir in El Camino Park, the siting and construction of several emergency supply wells, and the upgrade of several existing wells and the Mayfield pump station. Upon completion, the city began to focus reliability efforts on its system of water storage reservoirs and transmission lines in the Foothills. At the same time that CPAU was evaluating the reliability of its own system, the SFPUC, in consultation with BAWSCA members, was evaluating the reliability of the Hetch Hetchy Regional Water System, which crosses two major fault lines between the Sierras and the Bay Area. That evaluation concluded that major upgrades to the system were required. This planning process culminated in the SFPUC’s $4.8 billion Water System Improvement Project (WSIP), which is ongoing. This has resulted and will continue to result in large increases in the annual debt service costs assigned to wholesale customers like Palo Alto. After each WSIP project is completed, wholesale customers must start paying the debt service costs within 3 to 4 years. The majority of those costs, funded with bond financing, will be paid off over approximately 30 years. The SFPUC WATER UTILITY FINANCIAL PLAN March 2021 14 | Page continues to evaluate its aging system for other needed infrastructure improvements; future major improvements include dam safety and Mountain Tunnel repairs. SECTION 4 B : CUSTOMER BASE CPAU’s Water Utility provides water service to the residents and businesses of Palo Alto, plus a handful of residential customers not in Palo Alto (primarily in Los Altos Hills). Approximately 20,100 customers are connected to the water system. Approximately 16,200 (81%) of these are separately metered residential customers and approximately 3,900 (19%) of these are commercial, master-metered residential, irrigation and fire service customers. Judging from seasonal consumption patterns, between 35% and 50% of Palo Alto’s water is used for irrigation, and that consumption is heavily weather dependent. It also varies significantly by season. As a result of these two factors, there is significant variability in the amount of water that is demanded from the system month to month and year to year. SECTION 4 C : DISTRIBUTION SYSTEM To deliver water to its customers, CPAU owns and operates roughly 236 miles of mains (which transport the water from the SFPUC meters at the city’s borders to the customer’s service laterals and meters), eight wells (to be used in emergencies), five water storage reservoirs (also for emergency purposes) and several tanks used to moderate pressure and deal with peaks in flow and demand (due to fire suppression, heavy usage times, etc.). These represent the vast majority of the infrastructure used to distribute water in Palo Alto. SECTION 4 D : COST STRUCTURE AND REVENUE SOURCES As shown in Figure 1, water purchase costs accounted for 47% of the Water Utility’s costs in FY 2020, Operational costs represented 40%, and capital investment was responsible for the remaining 13%. Staff projects these percentage distributions to remain similar over the forecast period. Figure 1: Cost Structure (FY 2020) 47% 40% 13% Supply Operations Capital WATER UTILITY FINANCIAL PLAN March 2021 15 | Page The Water Utility’s revenue is primarily from sales of water and the remainder from capacity and connection fees, interest on reserves, and other sources. Appendix A: Water Utility Financial Forecast Detail shows more detail on the utility’s cost and revenue structures. Approximately 16% of the utility’s revenues come from fixed service charges, though most of its costs are fixed. SECTION 4 E : RESERVES STRUCTURE CPAU maintains six reserves for its Water Utility to manage various types of contingencies. The descriptions below summarize these reserves; see Appendix C: Water 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, as well as to manage cash flow for ongoing capital projects. This reserve can also act as a contingency reserve for the CIP. This type of reserve is used in other utility funds (Electric, Gas, and Wastewater Collection) as well. • Rate Stabilization Reserve: This reserve is intended to be empty unless the city anticipates one or more large rate increases 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, Gas, and Wastewater Collection) as well. • Operations Reserve: This is the primary contingency reserve for the Water Utility, and is used to manage yearly variances from the budget for operational water supply costs. This type of reserve is used in other utility funds (Electric, Gas, 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 : COMPETITIVENESS Table 8 shows the current water bills for single-family residential customers compared to what they would be under surrounding communities’ rate schedules. CPAU is among the highest monthly bills of the group, although bills for smaller water users are less than in some Figure 2: Revenue Structure (FY 2020) 93% 7% Sales of Water Other Revenue WATER UTILITY FINANCIAL PLAN March 2021 16 | Page surrounding communities. These comparison cities are the cities CPAU compares itself to in the annual budget across all industries. Table 8: Single-Family Residential Monthly Water Bill Comparison Usage (CCF/month) Residential monthly bill comparison ($/month)* As of January 2021 Palo Alto Menlo Park Mountain View Hayward Redwood City Santa Clara Los Altos 4 $46.89 $52.42 $38.34 $39.20 $54.04 $44.62 $42.99 (Winter median) 7 $70.28 $77.50 $59.37 $60.62 $76.09 $63.91 $60.84 (Annual median) 9 $90.42 $94.23 $73.39 $74.90 $90.79 $76.77 $72.73 (Summer median) 14 $140.77 $136.31 $108.44 $112.51 $138.94 $108.92 $101.62 25 $251.54 $229.06 $227.65 $205.02 $267.39 $179.65 $169.20 * Based on the FY 2013 BAWSCA survey, the fraction of SFPUC as the source of potable water supply was 100% for Palo Alto, 95% for Menlo Park, 100% for Redwood City, 87% for Mountain View, 10% for Santa Clara and 100% for Hayward. Los Altos does not receive water supply from SFPUC. SECTION 5 : UTILITY FINANCIAL PROJECTIONS SECTION 5 A : LOAD FORECAST Figure 4 shows 40 years of water consumption history. Average water use has trended downward over time even as Palo Alto’s population has grown. Significant water use reductions over the 40- year history were in response to requests to reduce water use in the 1976-77 and 1988-92 drought periods. During these periods, customers invested in efficient equipment and modified behavior to achieve water reduction goals. Reductions in usage achieved during these drought periods endured even after those periods. More recently, water sales decreased substantially during the 2007-2009 recession and drought and during the 2014-2017 drought. Usage has started to return to pre-drought levels, though the level at which usage will finally plateau is unknown. WATER UTILITY FINANCIAL PLAN March 2021 17 | Page Figure 3: Historical Water Consumption Figure 4 shows the financial plan forecast of water consumption through FY 2026, as denoted by the dotted line. Figure 4: Forecast Water Consumption During the recent drought, the State mandated a 24% water use restriction for Palo Alto until May 2016. Customers continue to conserve, but water usage has been increasing. In FY 2020 consumption was influenced by both dry weather and COVID-19 impacts to residents and businesses. This forecast is based on consumption levels in FY 2018 through FY 2020 and assumes a continuation of the long-term usage declines over time. WATER UTILITY FINANCIAL PLAN March 2021 18 | Page SECTION 5 B : FY 2016 TO FY 2020 COST AND REVENUE TRENDS Figure 5 and the tables in Appendix A: Water Utility Financial Forecast Detail show how costs have changed during the last five years as well as how staff projects they will change over the next five years. The annual expenses for the water utility rose substantially between 2016 and 2020. The increases were related to both water purchase costs and operations costs. Water purchase costs increased 24% from $17.6 million in FY 2016 to $21.8 million in FY 2020. Section 6A: Water Purchase Costs contains a more in-depth discussion of water purchase costs. Operations costs increased by about 21% from FY 2016 to FY 2020 while CIP costs have generally increased but fluctuated down in certain years. For example, in FY 2017, a water main replacement project that CPAU put out for bid resulted in very few contractors competing, and project bids that were higher than budgeted. This led to delays due to the changing market conditions and rising CIP costs. Section 6B: Operations contains more detail regarding operations costs and Section 6C: Capital Improvement Program (CIP) provides more detail regarding CIP costs. Note that in Figure 5, Capital Investment in the projected years reflects one-time transfers as well as the annual capital program contribution to the CIP Reserve. WATER UTILITY FINANCIAL PLAN March 2021 19 | Page Figure 5: Water Utility Expenses, Revenues, and Rate Changes: Actual Expenses through FY 2020 and Projections through FY 2026 SECTION 5 C : FY 2020 RESULTS Actual sales revenues for FY 2020 were higher than projected ($47.1 million vs. $45.5 million). Operating costs and capital funding needs were lower during FY 2020, mainly due to deferrals of capital spending, and lower than expected water purchase costs due to low non-revenue water. Table 8 summarizes the variances from forecast. Table 9: FY 2020, Actual Results vs. Financial Plan Forecast Net Cost/ (Benefit) ($000) Type of change Higher sales revenues $(1,643) Higher revenues Capital deferrals $(13,679) Cost savings Water purchases lower than expected $(404) Cost savings Operating Expense higher than expected $226 Cost increase Net Cost / (Benefit) of Variances $(15,501) SECTION 5 D : FY 2021 PROJECTIONS Estimated sales revenues are expected to be higher than forecasted in the FY 2021 Financial Plan by about $1.8 million while other revenue is expected to be lower than forecasted by $1.4 million. Total revenue is expected to be $0.4 million higher than forecasted. The higher sales revenue is WATER UTILITY FINANCIAL PLAN March 2021 20 | Page in part because the sales decreases forecasted in the FY 2021 Financial Plan, which were made in light of the COVID-19 pandemic and related economic impacts, have not materialized. Water purchase costs are expected to be higher than anticipated in the FY 2021 Financial Plan due to updated sales forecasts. The FY 2021 Financial Plan estimated the CIP funding needed for FY 2021 to be $5.8 million while the current estimated CIP funding needed for FY 2021 is $3.5 million, a difference of approximately $2.3 million. Operations & Maintenance expense decreases are anticipated from lower than expected budgets. Table 10 summarizes the changes from the FY 2021 forecast. Table 10: FY 2021 Change in Projected Results, 2021 Forecast vs 2022 Forecast ($000) Net Cost/ (Benefit) Type of Change Sales Revenue ($1,826) Revenue increase Other Revenue (Including Interest Income) $1,394 Revenue decrease Water Purchases $858 Cost increase Capital Program Funding ($2,344) Cost decrease Operations & Maintenance Costs ($869) Cost decrease Net Cost / (Benefit) of Variances ($2,787) SECTION 5 E : FY 2022 – FY 2026 PROJECTIONS Figure 5 above shows that on average the costs for the Water Utility are increasing through the rest of the forecast period, though mainly after FY 2022 based on current estimates from the SFPUC. Water supply costs are the largest component and are generally projected to grow by about 6 percent on average over the forecast period FY 2022 – FY 2026. Operations and capital costs are also expected to increase at the same rate of inflation used in the City’s preliminary financial projections (3% to 5% per year). While future CIP costs have been revised upwards to reflect the higher construction costs seen in recent projects, there is still uncertainty with regard to the utility’s future costs for main replacement. See Section 6: Details and Assumptions for more detail on the costs that make up these projections, as well as the various assumptions underlying the projections. This Financial Plan addresses revenue losses due to COVID-19 and the ongoing associated economic effects. So far, the Water Utility has experienced sales and revenue losses in the commercial customer class and sales and revenue increases from residential customers. From March 2020 through December 2020, months impacted by the COVID-19 pandemic, commercial water sales were approximately 12% lower than the same months in 2018 and 13% lower than the same months in 2019. However, these reductions in water sales were offset by the increases in residential water sales. The resulting total water sales were 3% higher during March through December 2020 than during the same months in 2019 and 2018. Because weather was also dry during the same time period, which also tends to increase water sales, COVID-19-related sales impacts are not able to be determined with specificity. Staff will continue to monitor water sales and will recommend adjustments in next year’s financial plan as needed. As shown in Figure 5, above the Water Utility requires rate increases of between 0% and 5% per year through FY 2026 to provide sufficient revenues to fund annual expenses. This forecast assumes the use of the Rate Stabilization Reserve annually beginning in FY 2024 to spread the series of large water supply rate increases expected from the SFPUC over multiple years. In addition, the CIP Reserve is used to WATER UTILITY FINANCIAL PLAN March 2021 21 | Page provide capital funding going forward as well as stabilize rates by stabilizing fluctuations from year to year in capital spending. Annually, beginning in FY 2021, a fixed funding amount began to be provided from the Operations Reserve to the CIP Reserve to fund capital improvements. The proposed amount for FY 2022 is $8.24 million as shown in Table 3, rows 9 and 10. This amount is an estimate of the amount of CIP work there is in a given year, spread out over the forecast period. It was derived by calculating the approximate average annual CIP budget for FY 2022 through FY 2026 less an allowance for unspent funds and excluding the one-time reservoir replacement costs. The reservoir replacement costs will be funded through the one-time transfers of $5 million in FY 2022, $3.5 million in FY 2023 and $3.5 million in FY 2026 from the Operations Reserve to the CIP Reserve. Table 3 shows these transfers in row 8. This approach provides stability to the Operations Reserve by providing for a steady funding stream for CIP work and by reflecting fluctuations due to CIP such as project delays or accelerations in the CIP Reserve; ultimately, this stability should provide more stable customer rates. The use of the CIP Reserve in this way isolates fluctuations due to CIP delays or accelerations and allow those to be viewed together in the CIP Reserve. Conversely, other trends or factors affecting the Operations Reserve will be easier to identify and communicate in that reserve. Without the capital program contribution to the CIP Reserve, the relative stability of total costs, and revenues shown in Figure 5 would fluctuate greatly from year to year as shown below in Figure 6. WATER UTILITY FINANCIAL PLAN March 2021 22 | Page Figure 6: Water Utility Expenses, Revenues, and Rate Changes: Actual Expenses through FY 2020 and Projections through FY 2026 Note that the fluctuations in CIP show a mismatch in many forecasted years between revenues and costs. Isolating fluctuations in capital investment in the CIP Reserve not only helps provide adequate funding for needed capital improvements but also shows a more realistic view of the relationship between costs and revenues as shown in Figure 5. Figure 7 shows reserves trends based on these cost and revenue projections. The figure shows credit to the Rate Stabilization Reserve in FY 2020 and the contributions from the Rate Stabilization Reserve to the Operations Reserve in FY 2024 through FY 2026. Staff expects the Operations Reserve, the main contingency reserve, to be within the target range by the end of FY 2023 and for the remainder of the forecast period, and that this reserve will be adequate to meet all identified risks, as discussed in Section 5F: Risk Assessment and Reserves Adequacy. In addition, the Unassigned Reserve reflects reserve funds in the Operations Reserve above the maximum guideline level. These funds will be needed for the reservoir replacement projects. These excess reserves will be utilized by the end of FY 2023 and must be used before Rate Stabilization Reserve funds are utilized. WATER UTILITY FINANCIAL PLAN March 2021 23 | Page Figure 7: Water Utility Reserves Actual Year End Reserve Levels for FY 2020 and Projections through FY 2026 SECTION 5 F : RISK ASSESSMENT AND RESERVES ADEQUACY The Water Utility’s main contingency reserve is the Operations Reserve, and this Financial Plan proposes using funds and raising rates slowly such that reserves remain well within the guideline levels throughout the forecast period, as shown in Figure 8. Staff will consider funds in the Operations Reserve in excess of the maximum to be unassigned. The Operations Reserve is projected to exceed both the minimum reserve level and the short term risk assessment level throughout the forecast period. WATER UTILITY FINANCIAL PLAN March 2021 24 | Page Figure 8: Operations Reserve Adequacy Table 10 summarizes the risk assessment calculation for the Water Utility through FY 2026. The risk assessment includes the revenue shortfall that could accrue due to lower than forecasted sales revenue. Table 11: Water Risk Assessment ($000) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Total non-commodity revenue $26,322 $26,782 $28,142 $28,728 $29,769 Max. revenue variance, previous ten years 13% 13% 13% 13% 13% Risk of revenue loss $2,374 $2,416 $2,539 $2,592 $2,685 Total Risk Assessment value $2,374 $2,416 $2,539 $2,592 $2,685 SECTION 5 G : ALTERNATE SCENARIO There is no alternate scenario presented in this Financial Plan. SECTION 5 H : LONG-TERM OUTLOOK CPAU has put its Water Utility on strong footing by investing in its distribution system infrastructure and emergency water facilities over the last 20 years. The Water System Master Plan, completed in FY 2016 evaluated the current state of the distribution system and determined the necessary rate of main replacement in the next 20 years. This study factored in seismically vulnerable mains as well as deteriorating mains.. In addition, CPAU’s water supplier, the SFPUC, WATER UTILITY FINANCIAL PLAN March 2021 25 | Page has replaced and seismically strengthened its water transmission infrastructure, which will benefit Palo Alto and all Hetch Hetchy Regional Water System customers over the long term. The opportunities for CPAU’s Water Utility to obtain additional supplies over the long term may be in alternative water supplies such as recycled water, groundwater, and water from Valley Water. These alternatives have been analyzed in the past, and were analyzed again most recently in the 2017 Water Integrated Resource Plan 1 . Some of these alternatives may provide cost savings or increased drought protection. For example, in November, 2019, the City of Palo Alto entered into an agreement with Valley Water and the City of Mountain View that will provide (1) funding for a salt removal facility at the Regional Water Quality Control Plant in Palo Alto to improve the quality of non-potable recycled water used in Palo Alto and Mountain View, (2) a transfer of treated wastewater from Palo Alto to Valley Water for use in the county south of Mountain View, and (3) Palo Alto and Mountain View will have a future option to request new potable or non-potable water supply from Valley Water if needed. Climate change may begin to present challenges for the Water Utility over the next 20 to 40 years. Availability of water from SFPUC’s Regional Water System may change with changing seasonal precipitation patterns. Water consumption patterns may change. Consumption could increase due to drier weather or decrease as customers become even more focused on water conservation. Droughts may become more frequent. The risk of wildfire in the foothills could increase, possibly threatening utility infrastructure or placing greater demands on it. Sea level rise could result in greater exposure of utility infrastructure to inundation, possibly resulting in higher maintenance and replacement costs. As part of the Sustainability/Climate Action Plan, CPAU is currently working on a Climate Change Adaptation Roadmap that will begin to assess some of these risks. SECTION 6 : DETAILS AND ASSUMPTIONS SECTION 6 A : WATER P URCHASE COSTS CPAU purchases all of its potable water supplies from the SFPUC, which owns and operates the Hetch Hetchy Regional Water System. CPAU is one of several agencies that purchase water from the SFPUC, all of whom are members of the Bay Area Water Supply and Conservation Agency (BAWSCA). Palo Alto uses roughly 7% of the water delivered by the SFPUC to BAWSCA member agencies. In January 2021, the SFPUC provided an informal estimate for FY 2022 wholesale water rates to remain at $4.10 per CCF. The Hetch Hetchy Regional Water System begins with a system of reservoirs and tunnels in the high Sierra in Yosemite County and water is transported by a gravity-fed pipeline to the Bay Area. Currently, the SFPUC is in the midst of a $4.8 billion bond-financed capital improvement program (the Water System Improvement Program, or WSIP) to seismically retrofit the facilities that transport water to the Bay Area. As of September 30, 2020, 98.8% of the WSIP regional projects 1 2017 Water Integrated Resource Plan: https://www.cityofpaloalto.org/civicax/filebank/documents/56088 WATER UTILITY FINANCIAL PLAN March 2021 26 | Page are complete.2 This has resulted and will continue to result in large increases in the annual debt service costs assigned to wholesale customers like Palo Alto. After each WSIP project is completed, wholesale customers must start paying the debt service costs within 3 to 4 years. The currently estimated WSIP completion date is June 30, 2023, as adopted by the SFPUC in April of 2020. In large part because of these WSIP-related debt service costs, the SFPUC’s wholesale water rate has already increased from $1.43 per CCF in FY 2009 to $4.10 per CCF in FY 2021, and is forecast to increase to $5.59 per CCF by FY 2026 (these projections are subject to change based on future SFPUC budget estimates). Figure 9 shows the SFPUC’s actual wholesale water rate since FY 2009 and a projection through FY 2026 and beyond. Note that the wholesale water rate decreased in FY 2014, but the apparent rate decrease is due to a debt the BAWSCA agencies owed to SFPUC being directly paid by the BAWSCA agencies via bond financing. This cost is in addition to the wholesale water rate and adds about $0.35 to $0.45 per CCF to the wholesale rate. Parts of SFPUC’s system not included in the WSIP will also need rehabilitation after the WSIP is completed, and some of these projects are already included in the SFPUC’s rate projections, such as additional Transmission, Supply & Storage and Treatment system upgrade projects, and dam safety work slated to occur during the next 10 years. The SFPUC is also conducting condition assessments of other “up-country” facilities, located in the Sierras, in the coming years. Current estimates are that $1.8 billion will be needed between FY 2019 and FY 2028 primarily for these non-WSIP projects, but if these assessments identify other facilities that need replacement, it may result in additional rate increases as new debt is issued to finance the projects. Total deliveries from the Regional Water System were higher than the five year average in FY 2020. Although reservoir storage in the Regional Water System is at normal levels, precipitation was well below average in water year 2020 and has continued to be low at the beginning of water year 2021. If sales continue to trend higher than average, a rate increase is unlikely in FY 2022, however, if precipitation continues at below average levels, the SFPUC may call for voluntary water conservation measures. 2 First Quarter FY 2020 - 2021 WSIP Regional Quarterly Report,https://www.sfwater.org/modules/showdocument.aspx?documentid=16461 WATER UTILITY FINANCIAL PLAN March 2021 27 | Page Figure 9: Historical and Projected SFPUC Wholesale Water Rate During FY 2017 through FY 2020, the balancing account for SFPUC’s wholesale customers built up an over-collection of revenue due to wholesale customer revenues exceeding costs. There are several reasons contributing to this: SFPUC sold more wholesale water than its sales projection used for rate setting, there were cost savings in the wholesale revenue requirement due to the SFPUC’s debt refinancing, and BAWSCA’s annual review of the wholesale revenue requirement resulted in credits applied to the balancing account. These balancing account funds will be refunded approximately between FY 2021 and FY 2024, which allows some rate stabilization of SFPUC’s wholesale rates. If it weren’t for this rate stabilization effect of the balancing account, Palo Alto would pay higher rates in FY 2022 for water purchased from SFPUC. SECTION 6 B : OPERATIONS CPAU’s Water Utility operations include the following activities: • Administration, a category that includes charges allocated to the Water Utility for administrative services provided by the General Fund and for Utilities Department administration, as well as debt service and other potential transfers. Additional detail on Water 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 D: Description of Water Utility Operational Activities includes detailed descriptions of the work associated with each of these activities. From FY 2016 to FY 2020, overall operations costs increased 5% per year on average (see Figure 10). Operations and Maintenance costs and Resource Management costs were the primary reasons for the increase, driven primarily by increases in salaries and benefits. Transfers have WATER UTILITY FINANCIAL PLAN March 2021 28 | Page varied from year to year, but staff expect transfers to remain relatively low and stable through the forecast period. The financial plan projections align as much as possible with the City’s budget assumptions; instead of a ten-year General Fund Long Range Financial Forecast, the City presented a preliminary forecast focusing on FY 2022 based on the current economic climate and continued unknown impacts of the COVID-19 pandemic.3 This plan projects operations costs to increase by 2 to 3% per year, on average, over the forecast period. Underlying these projections are preliminary assumptions for non-salary and benefit cost categories from Palo Alto’s Office of Management and Budget. For salary and benefit assumptions, this financial plan uses estimated budget annual percentage increases applied to the actual 2020 salaries and benefits which is 8% in FY 2022 and an average of 3% per year in FY 2023 through FY 2026. These percentage estimates may change as the budget is refined and finalized this fiscal year. Figure 10: Historical and Projected Operational Costs SECTION 6 C : CAPITAL IMPROVEMENT PROGRAM (CIP) The Water Utility’s CIP consists of the following types of projects: 3 Staff Report #11844 WATER UTILITY FINANCIAL PLAN March 2021 29 | Page • One-time projects, or large, non-recurring replacement of system assets (such as reservoir rehabilitation). • Water main replacement, which represents the ongoing replacement of aging water mains and the services associated with those mains, as well as seismically vulnerable mains located in areas where soil is prone to liquefaction. • Ongoing projects, which represent the cost of replacing aging and under-recording meters and degraded boxes and covers, minor replacements of various types of distribution system equipment, and the cost of capitalized tools and equipment. • Customer connections, which represents the cost when the Water Utility installs new services or upgrades existing services at a customer’s request in response to development or redevelopment. CPAU charges a fee to these customers to cover the cost of these projects. Table 11 shows the FY 2021 projected budget and the five year CIP spending plan, although these figures are preliminary pending ongoing budget discussions. Table 12: Budgeted Water Utility CIP Spending ($000) This budget does not include allocated overhead, which is estimated to be $0.97 million in 2021 and escalating at 2-4% annually thereafter as shown in the table below. Allocated overhead is shown below and added to the capital budget as a capital expenditure. Table 13: Allocated Overhead FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Allocated Overhead $967,539 $1,006,627 $1,033,504 $1,064,510 $1,096,445 $1,121,882 The water main replacement program funds the replacement of deteriorating water mains or water mains in liquefaction zones. The water system consists of over 236 miles of mains, approximately 2,000 fire hydrants, and over 20,000 metered service connections spanning 9 pressure zones over a 26 square mile service area. In recent years, CPAU has already replaced many miles of the most leak-prone and deteriorated pipes. CPAU is currently pursuing a pipe replacement program of mains that are subject to recurring breaks based on maintenance history and 13.5 miles of mains that were identified in the 2015 water system study. CPAU also coordinates with the Public Works street maintenance program to avoid cutting into newly repaved streets. The main replacement schedule in this financial plan will allow CPAU to replace these mains on schedule. Costs for the water main replacement program are increasing for a variety of reasons: Project Category Current Budget* Spending, Curr. Yr Remain. Budget**Committed FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 One Time Projects 8,153 (50) 8,103 - 500 7,000 500 600 7,000 Water Main Replacement 3,659 (162) 3,497 - 8,925 425 8,925 425 9,350 Ongoing Projects 2,426 (718) 1,708 - 2,085 2,083 2,183 2,611 3,387 Customer Connections - (375) (375) - 877 905 932 961 989 TOTAL 14,238 (1,305) 12,933 - 12,388 10,413 12,540 4,596 20,726 *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). WATER UTILITY FINANCIAL PLAN March 2021 30 | Page • Fire Code regulations now mandate fire sprinklers for new residential units. To accommodate increased fire flows, new main replacement projects require larger diameter pipe. • CPAU has switched to high-density polyethylene (HDPE) for its mains. Installation costs for this material are slightly higher, though lifecycle costs are lower, and the material performs better. Joints in distribution mains are the most likely place for failure, and sections of HDPE pipe can be fused together rather than connected with fittings. In the long run, this will reduce losses and maintenance costs. • To take full advantage of HDPE’s fusibility, CPAU is now replacing the services along with the water mains with new HDPE services. In the past, the existing services were reconnected, regardless of the material. This new practice costs more in the short run, but will provide long term benefits. • Lastly, costs have escalated after the recession. The regional and even national focus on infrastructure improvement has created labor shortages in the construction market, leading to higher bids than were seen in the past. These factors have created some uncertainty in future water main replacement costs. As bids for recent projects have consistently come in higher over the last few years, future main replacement project budgets have been increased to reflect expected bid estimates. If the cost of water main replacement continues to rise at its current levels, budgets may need to be revised further. In 1993, the long term water main replacement program focused on replacing the oldest and most degraded parts of the system. Roughly 26% of the system has been replaced, and the rate of water leaks has decreased 50%. CPAU initiated a master planning process in FY 2015 that was completed in FY 2016 to evaluate the current state of the distribution system and determine the necessary rate of main replacement in the next 20 years. This study factored in seismically vulnerable mains as well as deteriorating mains. Mains with recurring maintenance issues are added to projects as they are identified. Preparing for the future, CPAU is in the process of evaluating the utility’s asbestos cement pipe (ACP) mains. Over half the mains in the system are ACP. The ACP pipe has performed very well, but CPAU wants to verify its life expectancy and plan for its future replacement in 20 to 30 years. This financial plan addresses these challenges in a way that will allow CPAU to meet its main replacement needs. This financial plan includes approximately $8.5 million every other year for main replacement construction. In prior years main replacement construction was planned at approximately $5.7 million annually. Staff anticipates that larger main replacement construction projects every other year will attract more contractors to bid on the larger projects. Included in the one-time project budget are seismic water system upgrades and/or replacement for the Park and Dahl reservoirs to improve earthquake resistance. This work will improve protection from water loss at these reservoirs in a seismic event. If an earthquake caused a significant water leak, this could lead to loss of water for firefighting, loss of water storage for drinking, property damage from flooding or mudslides, and environmental damages. Staff estimates the construction work and design for the replacement for Dahl and Park reservoirs will cost approximately $7 million each in FY 2023 and FY 2026. One project not included in this forecast is protecting the large water transmission line in the foothills from seismic events. To date the concrete cylinder pipe has performed well and is not in WATER UTILITY FINANCIAL PLAN March 2021 31 | Page need of immediate replacement. Once the storage issues are addressed, the focus will be to address the transmission main replacement. It could cost between $15 million and $20 million, which would likely require bond financing and would substantially affect the financial forecast. Ongoing Projects and Customer Connections are projected to cost approximately $3 million in FY 2021 and increase to approximately $4.3 million per year through the end of the forecast period. Actual expenses for these projects fluctuate annually depending on how many defective meters are discovered and replaced during routine maintenance, as well as how much development and redevelopment is going on that prompts the replacement or upgrade of water services. Property owners pay a fee for water service replacement or expansion during redevelopment, so when the number of projects go up (meaning higher costs for this activity), so does fee revenue. Aside from customer connections, the CIP plan for FY 2022 to FY 2026 is funded by revenue from utility rates and capacity fees. Appendix B: Water Utility Capital Improvement Program (CIP) Detail shows the details of the plan. Figure 11 below shows the projected CIP Reserve balances from FY 2022 through FY 2026. Figure 12 below shows the projected CIP expenditure fluctuating from year to year with the staggered main replacement schedule, relative to the more steady capital program contributions to the CIP Reserve. In FY 2022, the capital program contribution to the CIP Reserve is $8.24 million. The capital program contribution increases with inflation at a projected level of 3%. Appendix A: Water Utility Financial Forecast Detail shows the amount of the capital program contributions under “Expenses” for FY 2021 through FY 2026. WATER UTILITY FINANCIAL PLAN March 2021 32 | Page Figure 11: Projected CIP Reserve Balances FY 2021 to FY 2026 WATER UTILITY FINANCIAL PLAN March 2021 33 | Page Figure 12: Projected CIP Expenditure,and Projected Capital Program Contribution, FY 2021 to FY 2026 SECTION 6 D : DEBT SERVICE The Water Utility’s annual debt service is roughly $3.2 million per year. This is associated with two bond issuances, one requiring payments through 2026, the other through 2035. CPAU is in compliance with all covenants on both bonds. The first bond is the 2009 Water Revenue Bond, Series A, issued for $35 million to finance construction of the Emergency Water Supply and Storage project (the El Camino Reservoir, new wells, and rehabilitation of existing wells and tanks) which will be retired by 2035. As part of the ‘Build America’ bond program, there is an interest payment subsidy from the Federal Government of 35%. There is always the possibility that the federal government will choose to stop offering this subsidy. The automatic federal spending cuts under the Budget Control Act (BCA) of 2011 have already reduced the subsidy by $50,000 per year, and if planned cuts through 2021 proceed without amendment, staff estimates that the subsidy would be reduced by over $200,000 per year by 2021. The Bipartisan Budget Act of 2013, which relieved some of the discretionary spending cuts in the 2011 BCA, did not affect automatic cuts to the subsidy, and actually extended the automatic cuts through 2023. The second bond issuance is the 2011 Utility Revenue Refunding Bond, Series A, which is to be retired in 2026. This $17.2 million issuance refinanced an earlier Water and Gas Utility bond issuance, the 2002 Utility Revenue Bonds, Series A, which was issued to finance various capital WATER UTILITY FINANCIAL PLAN March 2021 34 | Page improvements for both systems. The Water Utility’s share of the issuance was roughly $7.8 million. Table 14 shows the cost of debt service for the Water Utility’s share of these bond issuances for the financial forecast period: Table 14: Water Utility Debt Service ($000) FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2009 Water Revenue Bonds, Series A (net of grants) 2,132 2,151 2,151 2,151 2,151 2011 Utility Revenue Bonds, Series A 657 658 658 658 658 Total 2,790 2,810 2,810 2,810 2,810 Both the 2009 and 2011 Bonds include the following covenants: 1) net revenues plus Available Reserves shall at least equal 125% of the maximum annual debt service, and 2) Available Reserves shall be at least 5 times the maximum annual debt service. Note that “Available Reserves,” as defined for both bonds, include the reserves for the Gas and Electric systems, not just the Water system. This Financial Plan maintains compliance with these covenants throughout the forecast period, as shown in Appendix A: Water Utility Financial Forecast Detail. SECTION 6 E : OTHER REVENUES The Water Utility receives most of its revenues from sales of water. The next largest source in FY 2020 was service connection fee revenue, which was higher than forecasted and represented 37% of revenue from sources other than water sales; interest income represented 28% of revenue from sources other than water sales, capacity fees and grants each represented approximately 13% of revenue from sources other than water sales. The remainder consisted of a variety of miscellaneous charges and transfers. Revenues from connection and capacity fees have more than doubled over the past 10 years since FY 2010. Connection and capacity fee revenue is reflected in the Operations Reserve. Connection fees are charged to new developments that need new or replacement service connections, while capacity fees are charged to development that put additional demands on the water distribution system. Revenue from these sources fluctuate from year to year. Over the past two years, capacity fees have been lower than the average of the last five years while service connection fees have been higher than the average of the past five years. In total, Staff is forecasting revenue from these sources to increase at an average of 2% per year in subsequent years. Other revenue sources are projected to stay stable through the forecast period, though interest income fluctuates depending on changes in interest rates. Some uncertainty also exists related to the Federal government’s commitment to continuing to pay the interest subsidy on the Build America Bonds. WATER UTILITY FINANCIAL PLAN March 2021 35 | Page SECTION 6 F : SALES REVENUES Staff based the sales revenue projections on the load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 5. Except where stated otherwise, these load forecasts are based on normal precipitation. Precipitation can vary substantially, and this can affect revenues substantially. In dry years customers use more water, increasing revenues, and in wet years they use less. It is difficult to predict customer usage recovery post-drought and during the ongoing pandemic. Staff will continue to monitor these patterns and adjust projections accordingly in subsequent financial plans. SECTION 7 : COMMUNICATIONS PLAN The Fiscal Year (FY) 2022 Water Utility communications strategy covers these primary areas: efficiency services and utility bill savings; capital improvement, operations and maintenance for infrastructure safety and reliability; sustainable water resources management; and cost containment measures. The City of Palo Alto Utilities (CPAU) communication methods include use of the utilities website, utility bill inserts, messaging on utility bills, email newsletters, print and digital ads in local publications, social media, and community messaging platforms. In FY 2022, CPAU is proposing no increase in water utility rates. FY 2021 year-end Operations Reserves are projected to be above guideline levels and within guideline levels by year end FY 2022. CPAU will utilize the capital reserve to promote reserve health and provide sufficient funds for critical capital investments. The focus of communications for water utility rates will continue to be on cost drivers for future rate increases which are expected to resume in 2023; what CPAU is doing to keep costs down; and the value of our customers’ investment through their rates. Future projections for FY 2023-2026 indicate that a 5% annual increase will be necessary to maintain adequate reserves within a healthy margin while paying for wholesale rate increases. One of the main reasons for future water utility rate increases includes the continual need for infrastructure upgrades along the local water distribution system to replace or maintain the water pipes, mains, and service connections. This necessary maintenance helps prevent leaks, which cost the utility and rate payers money, and prevents damage to infrastructure which could exacerbate safety and reliability concerns in the long term. Market economics have continued to drive up labor and material costs for construction projects. Additionally, CPAU must pay for commodity water rate increases from the City’s water supplier, the San Francisco Public Utilities Commission (SFPUC). Any increased supply costs are passed on to CPAU customers. As a not for profit public utility, CPAU must recover its costs primarily through revenue generated by rates. Staff maintain a dedicated webpage at cityofpaloalto.org/ratesoverview to provide an overview on all utility rates, including information on costs, utilities supply resources, infrastructure projects, and the value of what customers get for what they pay. While print materials and website pages feature prominently, CPAU is increasing the outreach emphasis on more direct communication with customers, including through use of social media, email newsletters, digital ads and videos. Aside from the 2020-2021 COVID-19 shelter-in-place public health order, staff typically attend community outreach events, safety and emergency preparedness fairs, and WATER UTILITY FINANCIAL PLAN March 2021 36 | Page neighborhood meetings to share information on our programs. One example of a new residential outreach opportunity is through providing information on the Cool Blocks curriculum. For the water utility, CPAU will continue its outreach on making water conservation a way of life, regardless of drought or rain conditions, which is in line with the State of California’s current outreach campaign. CPAU promotes available water use efficiency rebates, incentives and easy water-saving behaviors. Messaging reinforces the importance of water use efficiency, and that although rates may increase in the future, efficient usage can help customers avoid seeing a significant water cost increase on the utility bill. The City is also exploring opportunities to expand water reuse, such as through recycled water, to further reduce demands on potable water supplies. APPENDICES Appendix A: Water Utility Financial Forecast Detail Appendix B: Water Utility Capital Improvement Program (CIP) Detail Appendix C: Water Utility Reserves Management Practices Appendix D: Description of Water Utility Operational Activities Appendix E: Sample of Water Utility Outreach Communications APPENDIX A : WATER UTILITY FINANCIAL FORECAST DETAIL 1 FISCAL YEAR FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2 3 WATER SUPPLY 4 Purchases (CCF)4,127,085 4,172,038 4,859,576 4,600,987 4,757,199 4,775,311 4,713,232 4,651,960 4,591,484 4,531,795 4,472,882 5 Sales (CCF)3,858,825 3,852,185 4,609,893 4,411,473 4,670,827 4,567,464 4,508,087 4,449,481 4,391,638 4,334,547 4,278,198 6 7 BILL AND RATE CHANGES 8 Variable Charge (Supply)9%7%-6%0%0%0%0%8%6%12%6% 9 Residential Variable Charge (Distribution)5%-2%-4%0%-2%3%0%3%6%3%5% 10 System Average Rate 7%2%1%-1%0%0%0%5%6%7%6% 11 Average Customer Bill (projected)1%0%0%5%5%5%5% 12 13 STARTING RESERVES 14 Reappropriations (Non-CIP)- - - - 258,000 70,000 70,000 70,000 70,000 70,000 70,000 15 Commitments (Non-CIP)347,000 177,273 177,273 284,034 442,000 796,000 796,000 796,000 796,000 796,000 796,000 16 Restricted for Debt Service 3,316,000 3,299,194 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 17 Emergency Plant Replacement - - - - - - - - - - - 18 Reappropriations & Commitments 9,656,000 10,530,000 13,266,000 11,326,000 15,090,505 11,036,000 11,036,000 11,036,000 11,036,000 11,036,000 11,036,000 19 Capital Reserve 4,000,000 2,726,096 2,726,096 2,726,096 2,726,096 5,726,096 10,310,423 10,608,451 11,615,464 7,274,334 11,122,468 20 Rate Stabilization Reserve 6,567,000 1,877,437 4,069,437 4,069,437 4,069,437 9,069,437 9,069,437 9,069,437 9,069,437 5,000,000 3,000,000 21 Operations Reserve 11,663,836 14,606,828 12,734,948 13,741,000 12,438,456 13,351,122 13,288,922 13,778,100 9,251,924 11,717,950 11,585,196 22 Unassigned - - 7,056,052 7,182,707 8,213,544 6,489,877 7,395,474 574,713 - - - 23 TOTAL STARTING RESERVES 35,549,836 33,216,828 43,289,806 42,589,274 46,498,038 49,798,533 55,226,256 49,192,700 45,098,826 39,154,284 40,869,664 24 25 REVENUES 26 Net Sales 36,136,644 41,657,382 44,078,960 44,134,246 47,136,524 45,296,544 44,805,547 46,484,471 48,774,319 51,549,436 53,678,788 27 Other Revenues and Transfers In 3,258,936 5,829,851 4,116,200 5,218,976 3,927,307 3,967,324 4,011,255 4,055,483 4,121,960 4,189,677 4,273,851 28 TOTAL REVENUES 39,395,579 47,487,233 48,195,160 49,353,223 51,063,831 49,263,868 48,816,802 50,539,954 52,896,278 55,739,112 57,952,639 29 30 EXPENSES 31 Water Purchases 17,626,020 20,075,322 21,957,711 21,210,399 21,773,295 21,846,978 21,592,454 22,867,082 23,839,493 26,412,042 27,265,840 32 Operating Expenses 5.8% -54.7% 33 Administration 34 Allocated Charges 2,953,291 3,151,373 2,809,112 2,626,526 2,799,878 2,846,356 2,961,349 3,040,417 3,131,630 3,225,578 3,300,412 35 Rent 1,803,087 1,720,711 1,775,774 1,832,599 1,904,070 1,942,151 1,980,994 2,030,519 2,091,435 2,154,178 2,218,803 36 Debt Service 3,222,606 3,219,316 3,222,669 3,220,858 3,220,638 3,222,843 3,223,563 3,224,553 3,224,553 3,224,553 3,224,553 37 Transfers and Other Adjustments (377,200) (256,608) 393,607 438,322 474,953 484,452 494,141 504,024 1,124,104 1,134,386 1,144,874 38 Subtotal, Administration 7,601,785 7,834,792 8,201,161 8,118,304 8,399,539 8,495,802 8,660,047 8,799,513 9,571,721 9,738,695 9,888,642 39 Resource Management 592,744 868,038 922,558 963,976 1,159,106 1,174,522 1,245,228 1,280,531 1,318,946 1,358,515 1,381,066 40 Operations and Mtc 5,038,570 5,290,549 5,725,236 5,964,589 7,010,251 7,104,188 8,527,598 8,768,929 9,031,997 9,302,957 9,459,246 41 Engineering (Operating)282,472 355,852 354,597 383,877 401,902 408,051 427,719 439,417 452,600 466,178 475,781 42 Customer Service 2,076,559 1,616,008 1,625,332 1,620,421 1,865,571 1,887,771 2,017,272 2,075,874 2,138,150 2,202,295 2,232,687 43 Allowance for Unspent Budget - - - (427,929) - (496,841) (561,933) (577,703) (595,034) (612,885) (623,757) 44 Subtotal, Operating Expenses 15,592,128 15,965,239 16,828,885 16,623,240 18,836,369 18,573,494 20,315,932 20,786,560 21,918,380 22,455,754 22,813,665 45 Capital Program Contribution^9,082,021 4,110,131 8,169,097 11,791,292 3,265,168 8,000,000 8,240,000 8,487,200 8,741,816 9,004,070 9,274,193 46 TOTAL EXPENSES 42,300,170 40,150,692 46,955,693 49,624,930 43,874,831 48,420,472 50,148,386 52,140,842 54,499,689 57,871,866 59,353,698 47 48 ENDING RESERVES 49 Reappropriations (Non-CIP)- - - 258,000 70,000 70,000 70,000 70,000 70,000 70,000 70,000 50 Commitments (Non-CIP)177,273 177,273 284,034 442,000 796,000 796,000 796,000 796,000 796,000 796,000 796,000 51 Restricted for Debt Service 3,299,194 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 3,260,000 52 Emergency Plant Replacement - - - - - - - - - - - 53 Reappropriations & Commitments 10,530,000 13,266,000 11,326,000 15,090,505 11,036,000 11,036,000 11,036,000 11,036,000 11,036,000 11,036,000 11,036,000 54 Capital Reserve 2,726,096 2,726,096 2,726,096 2,726,096 5,726,096 10,310,423 10,608,451 11,615,464 7,274,334 11,122,468 2,601,935 55 Rate Stabilization Reserve 1,877,437 4,069,000 4,069,437 4,069,437 9,069,437 9,069,437 9,069,437 9,069,437 5,000,000 3,000,000 - 56 Operations Reserve 14,606,828 12,734,948 13,741,000 12,438,456 13,351,122 13,288,922 13,778,100 9,251,924 11,717,950 11,585,196 9,684,137 57 Unassigned - 7,056,052 7,182,707 8,213,544 6,489,877 7,395,474 574,713 - - - - 58 TOTAL ENDING RESERVES 33,216,828 43,289,369 42,589,274 46,498,038 49,798,533 55,226,256 49,192,700 45,098,826 39,154,284 40,869,664 27,448,072 ^ Capital Program Contribution represents levelized amount of CIP funding for the CIP Reserve beginning in FY 2021 Appendix A (continued) 1 FISCAL YEAR FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2 3 REVENUES 4 Net Sales 82%92%88%91%89%92%92%92%92%92%92%93% 5 Other Revenues and Transfers In 18%8%12%9%11%8%8%8%8%8%8%7% 6 TOTAL REVENUES 100%100%100%100%100%100%100%100%100%100%100%100% 7 8 EXPENSES 9 Water Purchases 39%42%50%47%43%50%45%43%44%44%46%46% 10 Operating Expenses 11 Administration 12 Allocated Charges 6%7%8%6%5%6%6%6%6%6%6%6% 13 Rent 6%4%4%4%4%4%4%4%4%4%4%4% 14 Debt Service 8%8%8%7%6%7%7%6%6%6%6%5% 15 Transfers and Other Adjustments 0%-1%-1%1%1%1%1%1%1%2%2%2% 16 Subtotal, Administration 20%18%20%17%16%19%18%17%17%18%17%17% 17 Resource Management 1%1%2%2%2%3%2%2%2%2%2%2% 18 Operations and Mtc 13%12%13%12%12%16%15%17%17%17%16%16% 19 Engineering (Operating)1%1%1%1%1%1%1%1%1%1%1%1% 20 Customer Service 5%5%4%3%3%4%4%4%4%4%4%4% 21 Allowance for Unspent Budget 0%0%0%0%-1%0%-1%-1%-1%-1%-1%-1% 22 Subtotal, Operating Expenses 39%37%40%36%33%43%38%41%40%40%39%38% 23 Capital Program Contribution 21%21%10%17%24%7%17%16%16%16%16%16% 24 TOTAL EXPENSES 100%100%100%100%100%100%100%100%100%100%100%100% 25 26 RISK ASSESSMENT DETAIL 27 Distribution Revenue Variance 1,684,153 1,826,395 1,877,534 1,877,534 1,638,217 2,443,814 2,396,824 2,374,493 2,415,969 2,538,630 2,591,503 2,685,422 28 10% CIP Program Contingency 858,037 908,202 411,013 816,910 1,179,129 326,517 - - - - - - 29 Total Risk Asssessment Value 2,542,190 2,734,598 2,288,548 2,694,444 2,817,346 2,770,331 2,396,824 2,374,493 2,415,969 2,538,630 2,591,503 2,685,422 30 Projected Operations Reserve 11,663,836 14,606,828 12,734,948 13,741,000 12,438,456 13,351,122 13,288,922 13,778,100 9,251,924 11,717,950 11,585,196 9,684,137 31 Operations Reserve, % of Risk Value 459%534%556%510%441%482%554%580%383%462%447%361% 32 33 OPERATIONS RESERVE 34 Min (60 days of non-capital expenses)5,230,611 5,145,323 6,320,551 6,375,879 6,219,228 6,675,561 6,644,461 6,889,050 7,175,941 7,521,842 8,033,062 8,232,247 35 Target (90 days of non-capital expenses)9,395,240 8,698,557 9,527,750 10,058,439 9,328,842 10,013,342 9,966,692 10,333,575 10,763,912 11,282,763 12,049,594 12,348,371 36 Max (120 days of non-capital expenses)13,559,870 12,251,790 12,734,948 13,741,000 12,438,456 13,351,122 13,288,922 13,778,100 14,351,882 15,043,684 16,066,125 16,464,495 37 Risk Assessment Value 2,542,190 2,734,598 2,288,548 2,694,444 2,817,346 2,770,331 2,396,824 2,374,493 2,415,969 2,538,630 2,591,503 2,685,422 38 39 DEBT SERVICE COVERAGE RATIO 40 Net Revenues (125% of Debt Service)878%931% 1020% 1104% 1075% 1161% 1154% 1200% 1254% 1319% 1415% 1453% 41 Available Reserves (5x Debt Service)*9.9 9.2 12.4 12.1 13.2 14.2 15.9 14.0 12.7 10.9 11.4 7.2 42 *For the purposes of debt covenants, the unrestricted reserves of other utilities may be counted toward the available reserves for meeting this measure. A ratio below 5x means that this utility is relying on the reserves of other utilities to meet its debt covenants. WATER UTILITY FINANCIAL PLAN March 2021 39 | Page APPENDIX B : WATER UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL Project # Project Name Reappropriated / Carried Forward from Previous Years Current Year Funding Proposed Budget Amendments Spending, Current Year Remaining in CIP Reserve Fund Commitments FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 ONE TIME PROJECTS WS-07000 Regulation Station Imp.681,394 - - (710) 680,684 - - - - - WS-07001 Water Recycling Facilities 391,020 - - - 391,020 - - - - - - WS-08001 Water Reservoir Coating - - - - - - - - - WS-09000 Seismic Water System 5,080,313 2,000,000 - (49,007) 7,031,306 - 500,000 7,000,000 500,000 600,000 7,000,000 Subtotal, One-time Projects 6,152,727 2,000,000 - (49,717) 8,103,010 - 500,000 7,000,000 500,000 600,000 7,000,000 WATER MAIN REPLACEMENT PROGRAM WS-12001 WMR- Project 26 - - 5 5 - - - - - - WS-13001 WMR - Project 27 3,096,590 - - (111,236) 2,985,354 - - - - - WS-14001 WMR - Project 28 562,516 - - (51,178) 511,338 - 8,500,000 - - - - WS-15002 WMR - Project 29 - - - - - - 425,000 425,000 8,500,000 - - WS-16001 WMR - Project 30 - - - - - - - - 425,000 425,000 8,500,000 WS-19001 WMR - Project 31 - - - - - - - - - - 850,000 Subtotal, Water Main Replacement Prog.3,659,106 - - (162,409) 3,496,697 - 8,925,000 425,000 8,925,000 425,000 9,350,000 ONGOING PROJECTS WS-80014 Services/Hydrants - - - (42,059) (42,059) 400,000 400,000 400,000 412,000 424,000 WS-80015 Water Meters 1 701,450 - (45,274) 656,177 546,364 562,755 579,638 600,000 1,688,757 WS-02014 W-G-W Utility GIS Data 810,730 (810,730) - (42,994) (42,994) 483,958 498,477 513,431 528,800 544,000 WS-13002 Equipment/Tools - 50,000 - (34,792) 15,208 100,000 50,000 50,000 50,000 50,000 WS-11003 Dist. Sys. Improvements 292,356 269,469 - (294,110) 267,715 277,553 285,880 294,456 305,000 314,000 WS-11004 Supply Sys. Improvements - 749,469 - (12,121) 737,348 277,553 285,880 345,131 715,000 366,000 WS-19000 Mayfield Reservoir 363,253 - - (246,351) 116,902 - - - - Subtotal, Ongoing Projects 1,466,340 959,658 - (717,701) 1,708,297 - 2,085,428 2,082,992 2,182,656 2,610,800 3,386,757 CUSTOMER CONNECTIONS (FEE FUNDED) WS-80013 Water System Extensions 72,365 (72,365) - (374,993) (374,993) 877,250 904,595 931,955 960,500 989,000 Subtotal, Customer Connections 72,365 (72,365) - (374,993) (374,993) - 877,250 904,595 931,955 960,500 989,000 GRAND TOTAL 11,350,538 2,887,293 - (1,304,820)12,933,011 - 12,387,678 10,412,587 12,539,611 4,596,300 20,725,757 Funding Sources Connection/Capacity Fees 1,860,946 - 1,815,524 1,845,990 1,895,819 1,939,875 - Other Utility Funds (Asset Mgmt, GIS Systems)313,242 - 322,640 332,320 342,286 352,533 350,000 Utility Rates 2,887,293 - 10,249,514 8,234,277 10,301,506 2,303,892 20,375,757 CIP-RELATED RESERVES DETAIL 6/30/2020 Actual 6/30/21 (Unaudited) Reappropriations & Commitments 11,350,538 12,933,011 WATER UTILITY FINANCIAL PLAN March 2021 40 | Page APPENDIX C : WATER UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices shall be used when developing the Water 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, for the Water Utility Financial Plan delivered in conjunction with the FY 2015 budget, FY 2015 to FY 2021 is 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. Reserves The Water Utility’s Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 3 (Reserve for Commitments) b) For operating and capital budgets re-appropriated from previous years, as described in Section 4 (Reserve for Re-appropriations) c) For cash flow management and contingencies related to the Water Utility’s Capital Improvement Program (CIP), as described in Section 5 (CIP Reserve) d) For rate stabilization, as described in Section 6 (Rate Stabilization Reserve) e) For operating contingencies, as described in Section 7 (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 8 (Unassigned Reserves). Section 3. Reserve for Commitments At the end of each fiscal year the Reserve for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Water Utility at that time. Section 4. Reserve for Re-appropriations At the end of each fiscal year the Reserve for Re-appropriations will be set to an amount equal to the amount of all remaining capital and non-capital budgets, if any, that will be re- appropriated to the following fiscal year in accordance with Palo Alto Municipal Code Section 2.28.090. Section 5. 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: WATER UTILITY FINANCIAL PLAN March 2021 41 | Page 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 and approved by Council resolution. Minimum Level 20% of the maximum CIP Reserve guideline level Maximum Level Average annual (12 month)4 CIP budget, for 48 months of budgeted CIP expenses5 b) Changes in Reserves: Staff is authorized to transfer funds between the CIP Reserve and the Reserve for Commitments when funds are added or removed from to that reserve 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: 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 there are funds in this reserve in excess of the maximum level staff must propose in the next Financial Plan to transfer these funds to another reserve, return the funds to ratepayers, or designate a specific use of the funds for CIP investments that will be made by the end of the next Financial Planning Period. Staff may also seek City Council to 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 6. 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 Water Utility Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the next Financial Planning Period. The Council may approve exceptions to this requirement, when proposed by staff to provide greater rate stabilization to customers. 4 Each month is calculated based upon 1/12 of the annual budget. 5 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to derive the annual average would be FY 2022 through FY 2025 etc. WATER UTILITY FINANCIAL PLAN March 2021 42 | Page Section 7. Operations Reserve The Operations Reserve is used to manage normal variations in costs and as a reserve for contingencies. Any portion of the Water Utility’s Fund Balance not included in the reserves described in Section 3-Section 6 above will be included in the Operations Reserve unless this reserve has reached its maximum level as set forth in Section 7(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 Water Utility shall be designed to return the Operations Reserve to its target level within four years. 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 Water Utility’s Fund Balance shall be automatically included in the Unassigned Reserve described in Section 8, below. Section 8. Unassigned Reserve If the Operations Reserve reaches its maximum level, any further additions to the Water 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 Water 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 2021, 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. WATER UTILITY FINANCIAL PLAN March 2021 43 | Page APPENDIX D : DESCRIPTION OF WATER UTILITY OPERATIONAL ACTIVITIES This appendix describes the activities associated with the various operational activities referred to in Section 6B: Operations of this Financial Plan. Administration: Accounting, purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well as shared communications services, CPAU administrative overhead, and billing system maintenance costs. This category also includes Water Utility debt service and rent paid to the General Fund for the land associated with reservoirs and various other facilities. Customer Service: This category includes the Water 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 work with large commercial customers who have more complex requirements for their water services. Engineering (Operating): The Water Utility’s engineers focus primarily on the CIP, but a small portion of their time is spent assisting with distribution system maintenance. Operations and Maintenance: This category includes the costs of a variety of distribution system maintenance activities, including: • investigating reports of damaged mains or services and performing emergency repairs; • testing and operating valves; • monitoring water quality and reservoir levels; • monitoring the status of the different pressure zones; • flushing water at hydrants and other closed end points of the system; • building and replacing water 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 tanks 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) Resource Management: This category includes water procurement, contract management, water resource planning, interaction with BAWSCA, the SFPUC, and Valley Water, and tracking of legislation and regulation related to the water industry. March 2021 44 | Page APPENDIX E : SAMPLE OF WATER UTILITY OUTREACH COMMUNICATIONS THE. FACTS ON LEAKS .UOIU U: S I OW (0 ACK liile March 3, 2021 www.cityofpaloalto.org WATER UTILITY FINANCIAL PLAN AND PROPOSED RATE CHANGES FOR FY 2022 Attachment C 2 AGENDA •Cost structure and drivers •Overview and bill impacts of rate proposal •Projections of costs, revenue, and reserves •Bill comparisons to neighboring utilities •Recommendation 3 WATER UTILITY COST STRUCTURE Cost to distribute water within Palo Alto, including: maintaining and replacing water infrastructure, customer service, billing, administration, etc. Cost to bring water to Palo Alto 4 SUPPLY COST DRIVERS •Water System Improvement Project (WSIP) •2002: advocacy by wholesale customers results in AB 1823 requiring SFPUC to adopt and implement the WSIP •In 2010 construction began -$4.8B, one of the largest water projects in the nation •Level of service goal: return to service in 24 hours after an earthquake 5 SUPPLY COST DRIVERS •WSIP spending 98.8% complete as of September 2020 •“Upcountry” system in the Sierra still needs work •Through Water Supply Agreement amendment, Wholesale Customers will have more oversight of 10-year CIP •Necessary and improves reliability, but supply costs will increase in the future as a result 6 OPERATIONS/CAPITAL COST DRIVERS •Healthcare, retirement, associated overhead costs continue to increase •Underground construction costs have increased substantially •Installation of back-up generators at pumping stations within five year forecast period •Construction costs have increased substantially •Large one-time costs related to emergency water supply and reservoir rehabilitation 7 WATER PROJECTIONS •FY 2022 proposal: •0% overall rate increase •FY 2020 year-end Operations Reserve •At max guideline level with additional funds considered unassigned •Projected to be within guideline levels by year end FY 2022 •Annual capital program contribution to CIP Reserve for rate stability, and availability of capital investment funds •Use Rate Stabilization Reserve to reduce impact of supply cost increases •Future projections •5% annual increases FY 2023 –FY 2026 8 WATER COST AND REVENUE PROJECTIONS 9 OPERATIONS RESERVE PROJECTIONS 10 CIP RESERVE PROJECTIONS 11 MONTHLY RESIDENTIAL BILL COMPARISON Palo Alto is 7% above comparison city average 12 MONTHLY COMMERCIAL BILL COMPARISON Palo Alto is 4% to 6% above the neighboring community average Redwood City Menlo Park (Cal Water) Mountain View Hayward Santa Clara Commercial (12 CCF)110.23$ 117.72$ 119.18$ 99.67$ 99.40$ 96.06$ 106.41$ Commercial (64 CCF)511.15$ 499.92$ 564.60$ 464.19$ 460.80$ 430.42$ 483.99$ Commercial (300 CCF)2,330.71$ 2,234.52$ 2,586.10$ 2,118.55$ 2,369.00$ 1,947.90$ 2,251.21$ Neighboring Communities Neighboring Community AveragePalo Alto Based on rates as of January 2021 13 RECOMMENDATION Staff and UAC Recommend that the Finance Committee Recommend that the Council Adopt a Resolution Approving: •FY 2022 Water Utility Financial Plan •A transfer of up to $13.24 million from the Operations Reserve to the CIP Reserve in FY 2022 City of Palo Alto (ID # 11953) Utilities Advisory Commission Staff Report Report Type: New Business Meeting Date: 3/3/2021 City of Palo Alto Page 1 Summary Title: Presentation on REC Exchange Program Title: Informational Update on REC Exchange Program for 2020 and 2021 in Accordance With the City's Amended Electric Supply Portfolio Carbon Neutral Plan From: City Manager Lead Department: Utilities Executive Summary On August 24, 2020 the Council approved amendments to the electric utility’s Carbon Neutral Plan that clarified and modified policies regarding the sales and exchanges of renewable energy credits (RECs) (Staff Report #11556). The amendments permitted the exchange of Bucket 1 (primarily in-state) RECs for Bucket 3 (primarily out of state) RECs, provided the City maintains compliance with State Renewable Portfolio Standard (RPS) regulations. A portion of the earnings from the program would be used to mitigate the economic impacts of the coronavirus pandemic, and the remainder would be reserved for local decarbonization programs. The amendments also adopted an hourly accounting methodology for managing the City’s electric portfolio and permitted the use of Bucket 3 RECs for managing any emissions impacts identified by the use of the hourly accounting methodology. Since then, staff has been purchasing and selling RECs for Calendar Year 2020 in accordance with the Carbon Neutral Plan amendments. The attached presentation summarizes the net earnings for 2020 from the program and its impacts on the City’s Power Content Label. It also provides projections for the program’s net earnings and Power Content Label impacts for 2021. For 2020, net earnings from the REC exchanges were $2.94 million, which is in line with staff’s projections from the time the Carbon Neutral Plan amendments were adopted in August. Staff was able to sell more Bucket 1 RECs than initially projected; however, Bucket 1 REC prices were lower than expected, and Bucket 3 REC prices were slightly higher than expected. For 2021, staff projects slightly lower net earnings from the program ($2.80 million), prima rily due to higher RPS requirement levels and higher Bucket 3 REC prices. This is an informational item and no Utilities Advisory Commission action is requested. Attachments: Staff: Jim Stack City of Palo Alto Page 2 • Attachment A: Presentation Marc h 3, 2021 www.cityofpaloalto.org REC EXCHANGE: CY 2020 UPDATE #2 Staff: Jim Stack • CITY OF PALO ALTO PART 1: CY 2020 REC EXCHANGE SUMMARY March 3, 2021 www.cityofpaloalto.org 3 REC EXCHANGE SUMMARY FOR CY 2020 Baseline (No Sales) REC Exchange Program (August Update) REC Exchange Program (Final Update) Total REC Sales Volume (MWh)--324,400 348,700 Bucket 3 REC Purchase Volume (MWh)--298,830 325,186 Total REC Sales Revenue ($M)--$3.70 $4.04 Bucket 3 REC Purchase Cost ($M)--$0.79 $1.10 Net Revenue ($M)--$2.91 $2.94 Bucket 1 RPS Level 67%23%22% Projected REC Prices: $15.25 for Bucket 1, $2.65 for Bucket 3 Actual REC Prices: $13.70 for Bucket 1, $3.40 for Bucket 3 ~CITY OF ~PALO ALTO 4 ELECTRIC SUPPLY PORTFOLIO IMPACT (CY 2020) • . CITY OF PALO ALTO 1,000,000 900,000 800,000 700,000 .c 3: ~ 600,000 ~ C. C. ::J 500,000 V') u 'i: .. u 400,000 ~ LLJ 300,000 200,000 100,000 Total Load ✓ (841,477 MWh) Solar -----------------· 1 :.:~~;;:'.:•d I ---------l (Ma,ket Powe<+ 1,- 0----------I ""'""""' REc,1 l!l!!li Wind CY 2020 CY 2020 w/ REC Exchanges 5 POWER CONTENT LABEL IMPACT (CY 2020) Base Portfolio With REC Exchange RPS Level: 69% Emissions Intensity: 7 kg CO2/MWh RPS Level: 23% Emissions Intensity: 128 kg CO2/MWh • . CITY OF PALO ALTO ~ 34% ■ 44% 11% ■ Large Hydro ■ Landfill Gas ■ Wind ■ Solar ~ Unspeci f ied Power 6 POWER CONTENT LABEL IMPACT (CY 2020) Base Portfolio After REC Exchange Eligible Renewable 67%23% Biomass 13%9% Geothermal 0%0% Small Hydro 1%1% Solar 40%8% Wind 13%5% Coal 0%0% Large Hydro 33%48% Natural Gas 0%0% Nuclear 0%0% Unspecified Sources 0%29% Emissions Intensity (kg CO2/MWh)7.0 128.0 • . CITY OF PALO ALTO PART 2: CY 2021 REC EXCHANGE PROJECTIONS March 3, 2021 www.cityofpaloalto.org 8 REC EXCHANGE PROJECTIONS FOR CY 2021 Baseline (No Sales) REC Exchange Program Total REC Sales Volume (MWh)--273,025 Bucket 3 REC Purchase Volume (MWh)--176,674 Total REC Sales Revenue ($M)--$3.69 Bucket 3 REC Purchase Cost ($M)--$0.88 Net Revenue ($M)--$2.80 Bucket 1 RPS Level 71%34% Projected REC Prices: $13.50 for Bucket 1, $5.00 for Bucket 3 ~CITY OF ~PALO ALTO 9 ELECTRIC SUPPLY PORTFOLIO IMPACT (CY 2021) • . CITY OF PALO ALTO 1,000,000 900,000 800,000 700,000 .c 3r: ~ 600,000 ~ Q. Q. ::I 500,000 V'l u ·;: ... u 400,000 .S! w 300,000 200,000 100,000 Solar Wind CY 2021 Total Load >--------------(819,548 MWh) --- --------------- "Unspecified Power" -=(/'///. (Market Power+ Unbundled RECs) Solar CY 2021 w/ REC Exchanges 10 POWER CONTENT LABEL IMPACT (CY 2021) Base Portfolio With REC Exchange RPS Level: 71% Emissions Intensity: 7 kg CO2/MWh RPS Level: 34% Emissions Intensity: 62 kg CO2/MWh • . CITY OF PALO ALTO 33% 469' ■ Land f ill Gas ■ Wind ■ Solar 11 POWER CONTENT LABEL IMPACT (CY 2021) Base Portfolio After REC Exchange Eligible Renewable 67%32% Biomass 13%7% Geothermal 0%0% Small Hydro 1%1% Solar 40%18% Wind 13%6% Coal 0%0% Large Hydro 33%54% Natural Gas 0%0% Nuclear 0%0% Unspecified Sources 0%14% Emissions Intensity (kg CO2/MWh)7.0 62.0• . CITY OF PALO ALTO Jim Stack, Ph.D. Senior Resource Planner james.stack@cityofpaloalto.org (650) 329-2314 CITY OF PALO ALTO