Riverside City Council
March 25, 2025

2024R I V E R S I D E P U B L I C U T I L I T I E S
SERVICE AREA POPULATION316,690RECORD PEAK DEMANDEnergy:Water:TOTAL OPERATING REVENUEEnergy:Water:CUSTOMERSEnergy:Water:CREDIT RATINGEnergy:Water:

OVERVIEWRiverside Public Utilities generates, transmits and distributes electricity to a 81.5-square-mile territory that includes the City of Riverside. We also deliver water to a 74.2-square-mile territory covering the majority of the City of Riverside.The Board of Public Utilities is comprised of nine volunteers who live in all seven wards of the City of Riverside. They are appointed by the City Council to four-year terms without compensation. Board members oversee Riverside Public Utilities’ policies, operations, revenues, expenditures, planning, and regulatory compliance. They provide an ongoing, year-round review of all actions by Riverside Public Utilities before any measure is sent to the elected AA- Fitch AA- S&P GlobalAA+ FitchAA+ S&P GlobalAa2 Moody’s 648 megawatts9/7/2022365 acre feet119 million gallons8/9/2005$427.4 million$81.3 million113,43666,570RiversidePublicUtilities.com OUR CORE VALUESSafetyHonesty and IntegrityTeamworkProfessionalismQuality ServiceCreativity and InnovationCommunity InvolvementEnvironmental StewardshipInclusiveness and Mutual Respect OUR VISIONOur customers will recognize Riverside Public Utilities as a unique community asset with a global reputation for innovation, sustainability and an enhanced quality of life.

OUR MISSIONThe City of Riverside Public Utilities Department is committed to the highest quality water and electric community.RELIABILITY & RESILIENCYTaking care of our infrastructure, so that it remains safe, and AFFORDABILITYbalancing affordable rates for our customers.SUSTAINABILITYEnsuring adequate power and water supply in the most environmentally responsible manner.CUSTOMER EXPERIENCEContinuing to provide reliable customer-centered service every day.OPERATIONAL EXCELLENCEImplementing new technologies that will enhance the customer experience and ensure the tradition of operational excellence.STRONG WORKFORCEDeveloping and supporting a workforce that is safe, prepared and engaged.

OURFOCUSAREAS
Arts, Culture and RecreationCommunity Well-BeingEconomic Opportunity Environmental StewardshipHigh Performing GovernmentInfrastructure, Mobility and Connectivity ENVISION RIVERSIDE 2025Community TrustSustainability and ResiliencyEquityInnovationFiscal ResponsibilityCROSS-CUTTING THREADS STRATEGIC PRIORITIESG O A L SACTIONSMETRICSCommunity Trust – Riverside is transparent and makes decisions based on sound policy, inclusive community engagement, involvement of City Boards & Commissions, and timely and reliable populations, and result in greater public good. Equity – Riverside is supportive of the City’s racial, ethnic, religious, sexual orientation, identity, geographic, and other attributes of diversity and is committed to advancing the fairness of treatment, recognition of rights, and equitable distribution of services to ensure every member of the Fiscal Responsibility – Riverside is a prudent steward of public funds and ensures responsible Innovation – Riverside is inventive and timely in meeting the community’s changing needs and prepares for the future through collaborative partnerships and adaptive processes.Sustainability and Resiliency – Riverside is committed to meeting the needs of the present without compromising the needs of the future and ensuring the City’s capacity to persevere, adapt and CROSS-CUTTING THREADS Infrastructure, Mobility & Connectivitycommunity and facilitates connection between people, place and information. Goal 6.1.Provide, expand and ensure equitable access to sustainable modes of transportation that connect people to opportunities such as employment, education, healthcare and community amenities.Goal 6.2. Maintain, protect and improve assets and infrastructure within the City’s built environment to ensure and enhance reliability, resiliency, sustainability and facilitate connectivity.Goal 6.3.Identify and pursue new and unique funding opportunities to develop, operate, maintain and renew infrastructure and programs that meet the community’s needs.Goal 6.4.Incorporate Smart City strategies into the planning and development of local infrastructure projects.

Environmental StewardshipChampion proactive and equitable climate solutions based in science to ensure clean air, safe water, a vibrant natural world, and a resilient green new economy for current and future generations.Goal 4.1.Rapidly decrease Riverside’s carbon footprint by acting urgently to reach a zero-carbon electric grid with the goal of reaching 100% zero-carbon electricity production by 2040 while continuing to ensure safe, reliable and affordable energy for all residents.Goal 4.2.Sustainably manage local water resources to maximize reliability and advance water reuse to ensure safe, reliable and affordable water to our community.Goal 4.3Implement local and support regional proactive policies and inclusive decision-making processes to deliver environmental justice and ensure that all residents breath healthy and clean air with the goal of having zero days of unhealthy air quality per the South Coast Air Quality District’s Air Quality Index (AQI).Goal 4.5.Maintain and conserve 30% of Riverside’s natural lands in green space including, but not limited to, agricultural lands and urban forests in order to protect and restore Riverside’s rich biodiversity and accelerate the natural removal of carbon, furthering our community’s climate resilience.Goal 4.6.Implement the requisite measures to achieve citywide carbon neutrality no later than 2040.

Goal 3.3. Cultivate a business climate that welcomes innovation, entrepreneurship and investment.Champion a thriving, enduring economy that provides opportunity for all.Economic Opportunity Community Well-BeingEnsure safe and inclusive neighborhoods where everyone can thrive.Goal 2.3. Strengthen neighborhood identities and improve community health and the physical environment through amenities and programs that foster an increased sense of community and enhanced feelings of pride and belonging citywide. Goal 2.6. Strengthen community preparedness for emergencies to ensure effective response and recovery.Per the Operational Workplan, Riverside Public Utilities will carry out Actions to implement the City Council’s Strategic Priorities and Goals below.

CITY COUNCILPatricia Lock DawsonMayorPhilip FalconeWard 1Clarissa CervantesWard 2Steven RobillardWard 3Chuck ConderWard 4Sean MillWard 5Jim PerryWard 6Steve HemenwayWard 7 BOARD OF PUBLIC UTILITIESGil Oceguera (Board Chair) Ward 7Rebeccah A. Goldware (Board Vice Chair) Ward 2Sandra Polichetti Ward 1Warren Avery Ward 3Gary Montgomery Ward 4 Nancy E. Melendez Ward 5Rosemary Heru Ward 6Peter Wohlgemuth Citywide / Ward 1Brian D. Siana Citywide / Ward 2 EXECUTIVE MANAGEMENTMike Futrell City ManagerRafael Guzman Assistant City ManagerDavid A. Garcia Utilities General ManagerBrian Seinturier Utilities Assistant General Manager Finance and AdministrationTracy Soto Utilities Assistant General Manager Strategic Initiatives Utilities Assistant General Manager Energy DeliveryScott M. Lesch Utilities Assistant General Manager Power Resources

TABLE OF CONTENTSOverviewOur MissionValues and GoalsExecutive Management, City Council and Board of Public UtilitiesOUR ELECTRICIndependent Auditors’ Report 9Management’s Discussion and Analysis 13Financial StatementsStatements of Net Position 32Statements of Revenues, Expenses and Changes in Net Position 34Statements of Cash Flows 35Notes to the Financial Statements 37Required Supplementary InformationSchedule of Proportionate Share of The Net Pension Liability 81Schedule of Contributions 83Schedule of Changes in Total OPEB Liability and Related Ratios 85Key Historical Operating Data 86OUR WATER Independent Auditors’ Report 93Management’s Discussion and Analysis 96Financial StatementsStatements of Net Position 110Statements of Revenues, Expenses and Changes in Net Position 112Statements of Cash Flows 113Notes to the Financial Statements 115Required Supplementary InformationSchedule of Proportionate Share of The Net Pension Liability 149Schedule of Contributions 151Schedule of Changes in Total OPEB Liability and Related Ratios 153Key Historical Operating Data 154

OURR I V E R S I D E P U B L I C U T I L I T I E S
CliftonLarsonAllen LLPCLAconnect.comINDEPENDENT AUDIT REPORT Honorable Mayor City of Riverside Riverside, California Report on the Audit of the Financial Statements Opinion We have audited the accompanying financial statements of the Electric Utility Enterprise Fund (Electric Utility) of the City of Riverside, as of and for the year ended June 30, 2024, and the related notes to the financial statements, as listed in the table of contents. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Electric Utility, as of June 30, 2024, and the changes in its financial position and its cash flows thereof for the year then ended in accordance with accounting principles generally accepted in the United States of America. Basis for Opinion We conducted our audit in accordance with auditing standards generally accepted in the United States of America (GAAS) and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Our responsibilities under those standards are further described in the Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Electric Utility and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Other Matter The financial statements of the Electric Utility as of June 30, 2023, were audited by other auditors whose report dated November 8, 2023, expressed an unmodified opinion on those financial statements. Emphasis of Matter As discussed in Note 1, the financial statements present only the Electric Utility and do not purport to, and do not present fairly the financial position of the City of Riverside, California, as of June 30, 2024, the changes in its financial position, or, where applicable, its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America. Our opinion is not modified with respect to this matter. Responsibilities of Management for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. CLA (CliftonLarsonAllen LLP) is an independent network member of CLA Global. SeeCLAglobal.com/disclaimer.9 Honorable Mayor and Members of the City Council City of Riverside Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS and Government Auditing Standards will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements. In performing an audit in accordance with GAAS and Government Auditing Standards, we: Exercise professional judgment and maintain professional skepticism throughout the audit. Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Electric s internal control. Accordingly, no such opinion is expressed. Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements. We are required to communicate with those charged with governance regarding, among other matters,the planned scope and timing of the audit, significant audit findings, and certain internal control related matters that we identified during the audit.

Honorable Mayor and Members of the City Council City of Riverside Required Supplementary Information Accounting principles generally accepted in the United States of America require that the discussion and analysis, the schedule of proportionate share of the net pension liability, the schedule of contributions of the defined benefit plans, and the schedule of the Electric proportionate share of of pla be presented to supplement the basic financial statements. Such information is the responsibility of management and, although not a part of the basic financial statements, is required by the Governmental Accounting Standards who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with GAAS, which consisted of inquiries of management about the methods of preparing the information and comparing the information inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance. Other Information Management is responsible for the other information included in the annual report. other information comprises the introductory section and operating statistical section but does not include the basic financial statements and our report thereon. opinion on the basic financial statements do not cover the other information, and we do not express an opinion or any form of assurance thereon. In connection with our audit of the basic financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the basic financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report. Other Reporting Required by Government Auditing Standards In accordance with Government Auditing Standards, we have also issued our report dated December 16, 2024, on our consideration of the City of internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. purpose of that report is solely to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the effectiveness of the City of internal control over financial reporting or on compliance. at report is an integral part of an audit performed in accordance with Government Auditing Standards in considering City of Riinternal control over financial reporting and compliance.

CliftonLarsonAllen LLP Irvine, California December 16, 2024 11

ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISAs management of Riverside Public Utilities, a department of the City of Riverside (the City), we offer the readers thisnarrative overview and analysis of the 2023-24 financial report for the periods ended June 30, 2024 and 2023 forRiverside’s Electric Utility (Electric Utility), an enterprise fund of the City. We encourage readers to consider theinformation presented here in conjunction with additional information furnished in our financial statements, which begin onpage 32 of this report. All amounts, unless otherwise indicated, are expressed in thousands of dollars.FINANCIAL HIGHLIGHTSDuring fiscal year 2023-24, two bonds were issued for the Electric Utility, 2023 Electric Revenue Refunding BondSeries A and 2024 Electric Revenue Bond Series A. In December 2023, the 2023 Electric Revenue Bonds Series Awith $31,390 principal were issued to fully refund the 2013 Electric Revenue Bonds Series A. In February 2024, the2024 Electric Revenue Bonds Series A with $213,295 principal were issued to fully refund the 2008 Electric RevenueBonds Series A and C and 2011 Electric Revenue Bonds Series A. The 2024 Electric Revenue Bonds Series A alsoincludes new funding for qualifying electric capital projects. As of June 30, 2024, the Electric Utility debt portfolio nolonger holds any variable rate bonds.Retail sales, net of uncollectibles/recovery were $350,036 and $347,016 for years ended June 30, 2024 and 2023,respectively. The increase in sales was primarily due to rate plan increases offset by decreased consumption.Operating expense related to production and purchased power increased by $3,652 primarily due to fuel restrictionson our Intermountain Power Project coal resource throughout fiscal year 2023-24 that forced the utility to forwardhedge significantly more energy.Operating expense reflects a non-cash pension accounting standard adjustment, which will continue to fluctuate basedon yearly actuarial information provided by the California Public Employees' Retirement System. The adjustment was$7,707 and $(1,308) at June 30, 2024 and 2023, respectively.Investment income on investments increased by $12,763 due to a fair market value adjustment of investments and ahigher overall interest rate in the current fiscal year.OVERVIEW OF THE FINANCIAL STATEMENTSThis discussion and analysis is intended to serve as an introduction to the Electric Utility’s financial statements. TheElectric Utility is a department of the City, and its activities are recorded in a separate enterprise fund. These financialstatements include only the activities for the Electric Utility and provide comparative information for the last two fiscalyears. Information on city-wide financial results is available in the City’s “Annual Comprehensive Financial Report" (ACFR).The Electric Utility’s financial statements are comprised of two components: 1) financial statements, and 2) notes to thefinancial statements. In addition, this report also contains other supplementary information to provide the reader additionalinformation about the Electric Utility, including historical sales, operating activities, and other relevant data.Included as part of the financial statements are three separate statements, which collectively provide an indication of theElectric Utility’s financial health.The present information on all of the Electric Utility’s assets, liabilities, deferred inflows andoutflows of resources and net position. The Statements of Net Position provide information about the nature and amount ofthe Electric Utility’s resources and obligations at a specific point in time.The report all of the Electric Utility’s revenues andexpenses for the periods shown.The report the cash provided and used by operating activities, as well as other cash sources,such as investment income and debt financing. They also report other cash uses such as payments for bond principal andcapital additions and improvements.The provide additional information that is essential to a full understanding of the dataprovided in the financial statements. The Notes to the Financial Statements can be found on pages 37 to 80 of this report.13MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC13 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISELECTRIC UTILITY FINANCIAL ANALYSISCONDENSED STATEMENTS OF NET POSITION202420232022Current and other assets$602,487$454,579$501,765Capital assets776,873785,321796,227Deferred outflows of resources34,67145,62424,943Total assets and deferred outflows of resources1,414,0311,285,5241,322,935Long-term debt outstanding712,106590,602615,834Other liabilities177,720174,333148,059Deferred inflows of resources15,67117,23753,479Total liabilities and deferred inflows of resources905,497782,172817,372Net investment in capital assets230,789254,225246,097Restricted94,23474,16364,422Unrestricted183,511174,964195,044Total net position$508,534$503,352$505,563ASSETS AND DEFERRED OUTFLOWS OF RESOURCES2024 compared to 2023 The Electric Utility’s total assets and deferred outflows of resources were $1,414,031, reflectingan increase of $128,507 (10.0%), primarily due to the following:Current and other assets, comprised of restricted and unrestricted assets, had a net increase of $147,908, primarilydue to the issuance of the 2023 and 2024 Electric Revenue Series A Bonds, which fully refunded the 2008 ElectricRevenue Series A and C Bonds, 2011 Electric Revenue Series A Bonds, and 2013 Electric Revenue Series A Bonds,along with new financing of capital projects for the Electric Utility. Additionally, there were increases of $10,369 inunrestricted cash and cash equivalents, as well as $3,510 in restricted cash and investments at fiscal agent formoneys held for the future payment of pension related costs.Capital assets decreased by $8,448 primarily due to current year accumulated depreciation of $35,548 offset byan increase of $27,095 in additions and improvements to the Electric distribution infrastructure system to improveservice and reliability to the Electric Utility’s customers. Additional capital asset information can be found in the “CapitalAssets and Debt Administration” section.Deferred outflows of resources decreased by $10,953 primarily due to decreases of $3,913 in deferred outflowsrelated to pension, $5,375 from the loss on refundings, and $1,571 in the fair market value of interest rate swaps.Additional information can be found in the “Interest Rate Swaps on Revenue Bonds” section of Note 4 Long-termObligation. 2023 compared to 2022 Total assets and deferred outflows of resources were $1,285,524, reflecting a decrease of$37,411 (2.8%), primarily due to the following: Current and other assets, comprised of restricted and unrestricted assets, had a net decrease of $47,186, primarilydue to a decrease of $12,833 in accounts receivable primarily due to renewed collection efforts post COVID-19, thedecrease of $26,341 in unrestricted cash and cash equivalents primarily due to the funding of capital projects, and thetransition of the net pension asset created as a result of GASB 68 to a net pension liability. The net decrease wasoffset by an increase of $10,388 in restricted cash and cash equivalents held by the City and ongoing operatingexpenditures.Capital assets decreased by $10,906 primarily due to current year depreciation of $28,970 offset by an increase of$18,150 in additions and improvements to the Electric distribution infrastructure system to improve service andreliability to the Electric Utility’s customers.14MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISDeferred outflows of resources increased by $20,681 primarily due to an increase of $25,763 in deferred outflowsrelated to pension, offset by the change of $4,353 in the fair market value of interest rate swaps.LIABILITIES AND DEFERRED INFLOWS OF RESOURCES2024 compared to 2023 The Electric Utility’s total liabilities and deferred inflows of resources were $905,497, an increaseof $123,325 (15.8%), due to the following:Long-term debt outstanding increased by $121,504 primarily due to the issuance of the 2023 and 2024 ElectricRevenue Series A Bonds, which was partially offset by the full refunding of the 2008 Electric Revenue Series A and CBonds, 2011 Electric Revenue Series A Bonds, and the 2013 Electric Revenue Series A Bonds. Additional debtinformation can be found in the “Capital Assets and Debt Administration” section.Other liabilities increased by $3,387 primarily due to increases of $5,479 in net pension liability and $4,733 in accruedinterest payable due to the 2023 and 2024 Electric Revenue Series A bond issuances. The increase was offset bydecreases of $4,097 in interest rate swaps due to the refunding of the 2008 Electric Revenue Series A and C Bondsand 2011 and 2013 Electric Revenue Series A Bonds, and $2,791 in nuclear decommissioning liability. Additionalnuclear decommissioning information can be found in Note 10.Deferred inflows of resources decreased by $1,566 primarily due to pension related adjustments, which included thechanges in assumptions, the differences between expected and actual experience and the change in projected versusactual earnings on pension plan investments as determined by the plan actuary. 2023 compared to 2022 Total liabilities and deferred inflows of resources were $782,172, a decrease of $35,200 (4.3%),due to the following: Long-term debt outstanding decreased by $25,232 primarily due to revenue bond and pension obligation bondprincipal payments. Other liabilities increased by $26,274 primarily due to an increase of $38,748 in net pension liability. The increase wasoffset by decreases of $4,808 due to the change in the fair market value of interest rate swaps, as well as $4,437 innuclear decommissioning liability, $2,687 in accounts payable, and $1,098 in unearned revenue.Deferred inflows of resources decreased by $36,242 primarily due to pension related adjustments, which included thechanges in assumptions, the differences between expected and actual experience and the change in projected versusactual earnings on pension plan investments as determined by the plan actuary. The decrease was offset by anincrease in the deferred inflows related to the leases.NET POSITION2024 compared to 2023 The Electric Utility’s net position, which represents the difference between the Electric Utility’stotal assets and deferred outflows of resources less total liabilities and deferred inflows of resources, totaled $508,534, anincrease of $5,182 (1.0%). The following represents the changes in components of net position:The largest portion of the Electric Utility’s total net position, $230,789 (45.4%), a decrease of $23,436, reflects its netinvestment in capital assets. Additional capital asset information can be found in the “Capital Assets and DebtAdministration” section.The restricted portion of net position totaled $94,234 (18.5%), an increase of $20,071, and represents resources thatare subject to external restrictions on how they may be used. These are reserved for items such as debt payments,Public Benefit Programs, and other legally restricted assets.The unrestricted portion of net position totaled $183,511 (36.1%), an increase of $8,547, which is primarily attributableto the use of bond proceeds to fund qualifying capital projects and positive operating results. Unrestricted net positionmay be used to meet the Electric Utility’s ongoing operational needs and obligations to customers and creditors.15MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC15 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSIS2023 compared to 2022 Total net position decreased by $2,211 (0.4%), to a total of $503,352. The following representsthe changes in components of net position: The largest portion of the Electric Utility’s total net position, $254,225 (50.5%), an increase of $8,128, reflects its netinvestment in capital assets.The restricted portion of net position totaled $74,163 (14.7%), an increase of $9,741, and represents resources thatare subject to external restrictions on how they may be used. These are reserved for items such as debt payments,Public Benefit Programs, and other legally restricted assets.The unrestricted portion of net position totaled $174,964 (34.8%), a decrease of $20,080 from prior year, which isprimarily attributable to a decrease in operating income mainly as a result of higher power costs and the use ofreserves to fund ongoing capital projects and decommissioning trusts, offset by an increase in investment income.Unrestricted net position may be used to meet the Electric Utility’s ongoing operational needs and obligations tocustomers and creditors.CONDENSED STATEMENTS OF CHANGES IN NET POSITION202420232022Revenues:Retail sales, net$350,036$347,016$338,558Wholesale sales-2,04389Transmission revenue39,93435,23332,245Investment income18,7155,952-Other revenues30,11330,74725,852Public Benefit Programs11,32810,2228,978Capital contributions7,5539,8547,667Total revenues457,679441,067413,389Expenses:Production and purchased power199,566195,914176,595Transmission54,24868,05265,996Distribution81,00568,05739,738Public Benefit Programs8,1746,7515,467Depreciation38,08138,18936,718Amortization200214134Loss on Investments--10,330Interest expenses and fiscal charges25,93423,77525,037Total expenses407,208400,952360,015Transfers to the City's general fund(45,289)(42,326)(39,436)Extraordinary item--(5,748)Changes in net position5,182(2,211)8,190Net position, July 1, as previously reported503,352505,563497,373Net position, June 30$508,534$503,352$505,56316MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISREVENUES BY SOURCES 2024 compared to 2023The Electric Utility’s total revenues of $457,679increased by $16,612 (3.8%) with changes in thefollowing:Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $350,036, a $3,020(0.9%) increase. Retail sales continue to be the primary revenue source for the Electric Utility. The increase in saleswas primarily due to rate plan increases offset by decreased consumption.Transmission revenues of $39,934 increased by $4,701 (13.3%) primarily due to Southern California Edison ExistingTransmission Contract pass through and true-up costs, resulting in a higher High Voltage Transmission RevenueRequirement rate for the Electric Utility.Other revenues of $30,113 decreased by $634 (2.1%), primarily due to decreases in greenhouse gas cap-and-tradeauction proceeds.Investment income on investments increased by $12,763 due to a fair market value adjustment of investments and ahigher overall interest rate in the current fiscal year.2023 compared to 2022 The Electric Utility’s total revenues of $441,067 increased by $27,678 (6.7%) with changes in thefollowing:Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $347,016, an$8,458 (2.5%) increase. Retail sales continue to be the primary revenue source for the Electric Utility. The increase insales was primarily due to rate plan increases, as well as decreased uncollectibles.Transmission revenues of $35,233 increased by $2,988 (9.3%) primarily due to an increase in the load requirementsand an increase in the average Transmission Revenue Requirement rate of $2.66 per megawatt hour.Other revenues of $30,747 increased by $4,895 (18.9%), primarily due to increases in greenhouse gas cap-and-tradeauction proceeds. 17MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC17 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISEXPENSES BY SOURCES 2024 compared to 2023 The Electric Utility’s total expenses, excluding general fund transfer, were $407,208, an increaseof $6,256 (1.6%). The increase was primarily due to the following:Production and purchased power expenses of $199,566 increased by $3,652 (1.9%) primarily due to fuel restrictionson our Intermountain Power Project coal resource throughout fiscal year 2023-24 that forced the utility to forwardhedge significantly more energy.Transmission expenses of $54,248 decreased by $13,804 (20.3%) mainly due to a decrease in Southern CaliforniaEdison's high voltage rate and a decrease in the load from the California Independent System Operator (CAISO).Distribution expenses of $81,005 increased by $12,948 (19.0%), mainly due to a non-cash pension adjustment of$7,707 compared to prior year of $(1,308) as a result of pension accounting standards, along with increases inadministrative and general operating expenses.2023 compared to 2022 The Electric Utility’s total expenses, excluding general fund transfer, were $400,952, an increaseof $40,937 (11.4%). The increase was primarily due to the following:Production and purchased power expenses of $195,914 increased by $19,319 (10.9%) primarily due to a combinationof exceptionally elevated winter natural gas prices and elevated power prices, along with global market disturbances.Transmission expenses of $68,052 increased by $2,056 (3.1%) mainly due to an increase in Southern CaliforniaEdison's high voltage rate and an increase in the transmission access charge from the California Independent SystemOperator (CAISO).Distribution expenses of $68,057 increased by $28,319 (71.3%), mainly due to a non-cash pension adjustment of$(1,308) compared to prior year of $(16,425) as a result of pension accounting standards, along with increases inadministrative and general operating expenses.Depreciation expense of $38,189 increased by $1,471 (4.0%), reflecting the completion of capital projects and theircurrent year depreciation.18MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISTRANSFERSPursuant to the City of Riverside Charter, the Electric Utility may transfer up to 11.5 percent of prior year’s gross operatingrevenues, including adjustments, to the City’s general fund. The City uses these funds to help provide needed publicservices to the residents of the City, including police, fire, parks, libraries and other benefits. The Electric Utility transferred$45,289 and $42,326 for 2024 and 2023, respectively, based on the gross operating revenue provisions in the City’sCharter. Additional information can be found in Note 12 of the accompanying financial statements.CAPITAL ASSETS AND DEBT ADMINISTRATIONCAPITAL ASSETSThe Electric Utility’s investment in capital assets includes investments in production, transmission, and distribution relatedfacilities, land, intangibles, construction in progress, as well as general items such as office equipment, furniture, etc.The following table summarizes the Electric Utility’s capital assets, net of accumulated depreciation, at June 30:202420232022Utility plantProduction$127,494$136,413$148,896Transmission29,15630,03928,044Distribution400,455408,103407,181General61,30363,03065,032Intangibles5,7368,03210,166Land56,43556,38653,042Intangibles, non-amortizable10,65110,65110,651Construction in progress85,23372,26272,724Total utility plant776,463784,916795,736Lease assets1Building125199286Machinery and equipment162156205Subscription-based information technology arrangements12350-Total lease assets410405491Total capital assets$776,873$785,321$796,2271GASB 87 Leases was implemented effective July 1, 2021. GASB 96 Subscription-Based Information Technology Arrangements (SBITA) wasimplemented effective July 1, 2022. For additional information, refer to Notes 1 and 13.2024 compared to 2023 The Electric Utility’s investment in capital assets, net of accumulated depreciation, was$776,873, a decrease of$8,448 (1.1%). The decrease resulted primarily from the current year depreciation offset by thefollowing significant capital projects:$8,528 in recurring expenditures such as transformer replacements, cable replacements, and the RiversideTransmission Reliability Project for additional generation import capability for a second point of interconnection withthe State’s high voltage transmission grid.$5,305 in substation improvements.$5,079 in underground improvements, such as distribution line extensions and underground cable replacements.$2,852 in donated underground electrical conduit, donated street lighting, and donated land rights and easement.19MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC19 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSIS2023 compared to 2022 Investment in capital assets, net of accumulated depreciation, was $785,321, a decrease of$10,906 (1.4%). The decrease resulted primarily from the current year depreciation offset by the following significantcapital projects: $8,801 in recurring expenditures such as transformer replacements, cable replacements, and the RiversideTransmission Reliability Project for additional generation import capability for a second point of interconnection withthe State’s high voltage transmission grid.$5,957 in underground improvements, such as distribution line extensions and underground cable replacements.$5,560 in system automation improvements such as advanced metering infrastructure, and major streetlight projects.$4,903 in donated underground electrical conduit, donated street lighting, and donated land rights and easement.Additional information regarding capital assets can be found in Notes 3 and 13 of the accompanying financial statements.DEBT ADMINISTRATIONThe following table summarizes outstanding long-term debt as of June 30:202420232022Revenue bonds$600,680$507,370$524,130Unamortized premium76,81542,45745,055Financed purchases--364Pension obligation bonds58,29163,40867,641Less: Current portion of outstanding debt(23,680)(22,633)(21,356)Total long-term debt$712,106$590,602$615,834The Electric Utility’s bond indentures require the Electric Utility to maintain a minimum debt service coverage ratio, asdefined by the bond covenants, of 1.10. The Electric Utility’s debt service coverage ratio was 2.31, 2.01, and 2.03 at June30, 2024, 2023 and 2022, respectively. This debt is backed by the revenues of the Electric Utility. Debt service coverageratio increased at June 30, 2024 due to increased net revenues compared to prior year along with a decrease in expenses,offset by increases in principal and interest payments on debt service. For additional information, see Note 4 of theaccompanying financial statements and Key Historical Operating Data section.2024 compared to 2023 The Electric Utility’s long-term debt increased by $121,504 (20.6%) to $712,106 as a result of thenew bond issuances.During fiscal year 2023-24, two bonds were issued for the Electric Utility, 2023 Electric Revenue Refunding Bond Series Aand 2024 Electric Revenue Bond Series A. In December 2023, the 2023 Electric Revenue Bonds Series A with $31,390principal were issued to fully refund the 2013 Electric Revenue Bonds Series A. In February 2024, the 2024 ElectricRevenue Bonds Series A with $213,295 principal were issued to fully refund the 2008 Electric Revenue Bonds Series Aand C and 2011 Electric Revenue Bonds Series A. The 2024 Electric Revenue Bonds Series A also includes new fundingfor qualifying electric capital projects. As of June 30, 2024, the Electric Utility debt portfolio no longer holds any variablerate bonds.2023 compared to 2022 Long-term debt decreased by $25,232 (4.1%) to $590,602 as a result of current year principalpayments and amortization of bond premiums.Additional information on the Electric Utility’s long-term debt can be found in Note 4 of the accompanying financialstatements.CREDIT RATINGS The Electric Utility maintains a credit rating of “AA-” from S&P Global Ratings (S&P) and “AA-” from Fitch Ratings (Fitch).These ratings are a result of the Electric Utility's evolving power resource portfolio, which is well positioned to meetCalifornia's increasing environmental regulations with an emphasis on renewable energy resources, stable financialperformance and strong liquidity levels.20MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISREGULATORY, LEGISLATIVE FACTORS, AND RATES Utilities are faced with ongoing regulatory and legislative mandates enacted at the federal and state level that will havesignificant impact on the operations of the Electric Utility.ASSEMBLY BILL (AB) 32 – GLOBAL WARMING SOLUTIONS ACT OF 2006 AB 32, enacted in 2006, requires that utilities in California reduce their greenhouse gas (GHG) emissions to 1990 levels bythe year 2020. On September 8, 2016, the Governor of California expanded on this bill by approving Senate Bill 32 (SB32), which requires the state board to ensure that statewide greenhouse gas emissions are reduced to 40% below the1990 level by 2030.AB 32 tasked the California Air Resources Board (CARB) to develop regulations for GHG, which became effective January1, 2012. Emission compliance obligations under the cap-and-trade regulation began on January 1, 2013. The Cap-and-Trade Program (Program) was implemented in phases with the first phase starting from January 1, 2013 to December 31,2014. This phase placed an emission cap on electricity generators, importers and large industrial sources emitting morethan 25,000 metric tons of carbon dioxide-equivalent greenhouse gases per year. In 2015, the program expanded to coveremissions from transportation fuels, natural gas, propane, and other fossil fuels. Since the enactment of AB 32, theElectric Utility has actively participated with major investor-owned utilities and other publicly-owned utilities (POUs) to affectthe final rules and regulations with respect to AB 32 implementation.The Program requires electric utilities to have GHG allowances on an annual basis to offset GHG emissions associatedwith generating electricity. CARB will provide a free allocation of GHG allowances to each electric utility to mitigate retailrate impacts. If a utility requires additional allowances, then they must be purchased through the auction or on thesecondary market to offset its associated GHG emissions. Each allowance can be used for compliance purposes in thecurrent year or carried over for use for future year compliance. The Electric Utility’s free allocation of GHG allowances isexpected to be sufficient to meet the Electric Utility’s direct GHG compliance obligations.Any allowance not used for current year compliance or carried over for future use in compliance must be sold into thequarterly allowance auctions administered by CARB. Proceeds from the auctions must be used for the intended purposesas specified in AB 32, which include but are not limited to procurement of renewable resources, energy efficiency andconservation programs and measures that provide clear GHG reduction benefits. The Electric Utility is segregating theproceeds from the sales of allowances in the auctions as a restricted asset.Similar to the Cap-and-Trade Program, the Low Carbon Fuel Standard (LCFS) Program is a key component of themarket mechanisms authorized by AB 32 to achieve the State’s GHG emissions reduction goals. LCFS seeks to reducethe carbon intensity (CI) of fuels used for transportation by establishing an annual CI target. Fuels that have a CI greaterthan the target have a compliance obligation and are required to turn in LCFS credits, while fuels with a CI lower than thetarget may generate credits. In 2009, the LCFS rulemaking began and consisted of two rulemaking packages (Part 1 and Part 2) that was approved byCARB on January 12, 2010 and April 15, 2010, respecitively, with implementation effective January 1, 2011. The programthen underwent litigation in the State of California and the regulation was re-adopted with modifications on November 16,2015, effective January 1, 2016. Under the LCFS program, electricity is considered a fuel subject to the regulation when itis used as a transportation fuel in electric vehicles. However, because the CI of electricity is substantially lower than theannual CI targets under the program, then electricity is categorized as a fuel that generates LCFS credits and participationin the program is voluntary.In March 2018, the City opted into the LCFS program and began generating LCFS credits for the first quarter of 2018.These credits are associated with two sources – unmetered electricity used to charge residents’ electric vehicles at theirhomes (residential base credits) and from electric forklifts charging at private businesses (forklift credits). CARBcalculates the credits that the Electric Utility will receive and the Electric Utility submits quarterly reports to receive thecredits. The Electric Utility has established a restricted regulatory requirement reserve to comply with regulatoryrestrictions and governing requirements related to the use of the LCFS proceeds. The available funds are to be utilizedfor qualifying programs that support the Electric Utility’s customers who are existing and future electric vehicle owners.Simultaneously in 2018, the LCFS regulation was amended and adopted on January 4, 2019. The amendmentsrequired electric utilities that have opted into the LCFS Program to participate in and manage a statewide point-of-salerebate program for new electric vehicles. This program is called the California Clean Fuel Reward Program (CFR) andthe City joined the program in May 2020. To fund the program, electric utilities are required to contribute proceeds21MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC21 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISreceived from the sales of residential base credits beginning with the credits the Electric Utility received in the fourthquarter of 2019 (generated from electricity used for transportation in the second quarter of 2019). Residential basecredits the Electric Utility received prior to that time are not subject to the contribution requirements. Additionally, a “start-up” contribution from proceeds was required to be submitted by January 31, 2021. After the initial deposit of funds inNovember 2020, deposits to the CFR program are required by March 31 annually.CARB is currently in the midst of a new rulemaking process in which proposed amendments are anticipated to beconsidered in November 2024. The proposed amendments include changes to the residential base credits programincluding increasing the amount of holdback credit proceeds that must be used to support transportation electrification indisadvantaged communities to 75% and the possibility of up to 45% of base credits going to original equipmentmanufacturers (OEMs). If credits are directed to OEMs, electric utilities will no longer be required to contribute funds to theCFR program. Additional proposed amendments include the addition of an automatic acceleration mechanism for annualcarbon intensity benchmarks and additional verification requirements for annual compliance reports. The Electric Utility willcontinue to monitor the outcome and impacts of this rulemaking on its transportation electrification programs. SENATE BILL (SB) 1368 – EMISSION PERFORMANCE STANDARD The state legislature passed SB 1368 in 2006, which mandates that electric utilities are prohibited from making long-termfinancial commitments (commitments greater than five years in duration) for generating resources with capacity factorsgreater than 60 percent that exceed a GHG emission factor of 1,100 pounds per megawatt hour (lbs./MWh). SB 1368essentially prohibits any long-term investments in generating resources based on coal. Thus, SB 1368 initiallydisproportionally impacted Southern California POU’s as these utilities had heavily invested in coal technology. However,additional legislation such as SBX1-2, SB 350, SB 100, and SB 32 have now led to a gradual decrease in the generation ofexisting coal resources to serve load.The City has ownership entitlement rights to 136 MW of the Intermountain Power Plant (IPP). IPP has a GHG emissionfactor of approximately 2,000 lbs./MWh. Therefore, under SB 1368, the City is precluded from renewing its IPP PowerPurchase Contract at the end of its term in June 2027.Going forward, SB 1368 related issues are expected to have minimal impact to the CAISO markets as the percentage ofCalifornia load served by coal resources is small. However, to the extent that significant numbers of coal plants throughoutthe western United States (U.S.) start to retire in the next 5 to 15 years, it is possible that there can be a tightening ofsupply throughout the western U.S. electricity market. In turn, this can lead to higher regional costs and potentially reducedsystem reliability.ASSEMBLY BILL (AB) 2514 - ENERGY STORAGE AB 2514 “Energy Storage Systems” was signed into law on September 29, 2010. In 2012, AB 2227 amended the reportingtimeline of the energy storage targets referenced in AB 2514. The law directs the governing boards of POUs to considersetting targets for energy storage procurement, but emphasizes that any such targets must be consistent withtechnological viability and cost effectiveness. The law’s main directives for POUs and their respective deadlines are asfollows: (a) to open a proceeding by March 1, 2012 to determine appropriate targets, if any, for the utility to procure viableand cost-effective energy storage systems, and (b) to adopt an energy storage system procurement target by October 1,2014, if determined to be appropriate, to be achieved by the utility by December 31, 2016, and a 2ndtarget to be achievedby December 31, 2020. POUs were required to submit compliance reports to the CEC of their first adopted target byJanuary 1, 2017. Energy storage (ES) has been advocated as an effective means for addressing the growing operational problems ofintegrating intermittent renewable resources, as well as contributing to other applications on and off the grid. In general, ESis a set of technologies capable of storing previously generated electric energy and releasing that energy at a later time.Currently, the commercially available ES technologies (or soon to be available technologies) consist of pumped hydrogeneration, compressed air systems, batteries, and thermal ES systems.On February 17, 2012, as per the statute, the City of Riverside’s Board of Public Utilities opened a proceeding toinvestigate the various energy storage technologies available and determine if the City should adopt a 2016 energy storageprocurement target. The City finished its investigation of energy storage pricing and benefits in September 2014 andadopted a zero-megawatt target based on the conclusion that the viable applications of energy storage technologies andsolutions at the time were not cost effective and outweighed the benefits that it might provide to our electrical system. TheCity had to reevaluate its assessment by October 1, 2017 and report to the CEC any modifications to its initial targetresulting from this reevaluation.22MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISOn March 3, 2015, City Council approved the Ice Bear Pilot program for 5 MW. The program is intended to reduce loadduring peak hours by shifting load to off-peak hours, improve energy efficiency, and demonstrate the City’s proactivesupport of the State’s energy storage goals. Additionally, on July 28, 2015, the City Council approved a 20-year powerpurchase agreement for the City to procure renewable energy from the Antelope DSR Solar Photovoltaic Project thatincludes a built-in energy storage option for the buyers to exercise during the first fifteen years of operation.On December 12, 2016, Riverside submitted its first compliance report to the CEC describing Riverside’s proactive effortsin investigating viable energy storage options in the market and conducting energy storage pilot projects within the City tofulfill its first adopted target. On September 11, 2017 and September 26, 2017, after reevaluating its assessment of the first adopted energy storageprocurement target of zero megawatts, the Riverside Board and City Council, respectively, approved and adopted thesecond energy storage procurement target of six megawatts for submittal to the CEC.SENATE BILL (SB) 380 – MORATORIUM ON NATURAL GAS STORAGE – ALISO CANYON On October 23, 2015, a significant gas leak was discovered at the Aliso Canyon natural gas storage facility, which makesup 63% of total storage capacity and serves 17 gas fired power generation units. On May 10, 2016, the Governor ofCalifornia signed SB 380 placing a moratorium on Aliso Canyon’s natural gas storage usage until rigorous tests wereperformed and completed by the Division of Oil, Gas, and Geothermal Resources (DOGGR) as to which wells couldcontinue to be in operation. This moratorium caused great concern regarding reliability in the upcoming summer andwinter months. An action plan was initiated to review the summer and winter assessment. This action plan was conductedas a joint effort between the California Public Utilities Commission (CPUC), CEC, CAISO, and Los Angeles Department ofWater and Power (LADWP). Although the area of study does not include nor immediately impact Riverside, it is highlyplausible that the Electric Utility could still experience curtailed gas deliveries under certain adverse low-flow gasscenarios.Beginning June 1, 2016, Southern California Gas Company (SoCalGas) implemented new Operational Flow Order (OFO)tariffs due to limitations surrounding Aliso Canyon storage injections and withdrawals. These tariff changes were put inplace to reduce the probability of natural gas curtailments, which would disproportionally impact Riverside due to therequirements to operate internal natural gas generation to maintain system reliability during the summer. Also, gascurtailments during high peak days could lead to severe service curtailments throughout Riverside. Therefore, the ElectricUtility immediately increased internal communication across divisions, created internal gas curtailment procedures toaddress this specific issue, and created revised dispatch procedures when load forecasts exceed 400 MW. These tighterOFO tariff restrictions were scheduled to conclude upon the return of Aliso Canyon to at least 450 million cubic feet perday (MMcfd) of injection capacity and 1,395 MMcfd of withdrawal capacity. Aliso Canyon had not been able to meet itsinjection and withdrawal targets, therefore, these tighter OFO tariff restrictions continued to remain in effect. In addition,the Electric Utility continues to communicate daily with the CAISO and SoCalGas on any changes that could impact ourservice territory.On February 9, 2017, pursuant to SB 380, the CPUC opened a three-phase investigation to determine the feasibility ofminimizing or eliminating the use of Aliso Canyon. On July 19, 2017, DOGGR issued a press release on theirdetermination, in concurrence with the CPUC, that Aliso Canyon was safe to resume injections up to 28% of the facility’smaximum capacity. On that same day, the CEC issued a different press release with a recommendation urging closure ofAliso Canyon in the long-term. On July 31, 2017, SoCalGas resumed injections. Effective July 23, 2019, the CPUCapproved the Aliso Canyon Withdrawal Protocol, a protocol describing the process to follow before making a withdrawalfrom the natural gas storage facility. The protocol was developed with input from the CEC, the CAISO, and LADWP, andenables SoCalGas to withdraw from the Aliso Canyon natural gas storage facility when specific conditions are met relatedto Low Operational Flow Order (OFO) calculations, Southern California natural gas inventory levels, and/or emergencyconditions.Senate Bill 380 added Section 715 to the Public Utilities Code (PUC), which requires the CPUC to determine the range ofAliso Canyon inventory necessary to ensure safety, reliability, and just and reasonable rates. In the Section 715 Report,the Energy Division of the CPUC recommended that the maximum allowable Aliso Canyon inventory increase from 24.6 to34 billion cubic feet (Bcf) for summer 2018 and going forward, due to continuing pipeline outages on the SoCalGassystem. As of October 7, 2020, the final results of the 114 injection well tests are as follows: 66 wells have completed allrequired tests and have received final DOGGR (now the California Geologic Energy Management Division (CalGEM))approval; 27 wells have been taken out of operation; and 21 wells have been plugged and abandoned. The CalGEMreduced the Aliso Canyon safe inventory limit from 86Bcf to 68.6Bcf.23MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC23 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISOn November 4, 2021, the CPUC voted to allow SoCalGas to increase the amount of natural gas inventory at the AlisoCanyon Natural Gas Storage Facility from 34Bcf to 41.16Bcf, to ensure SoCalGas meets minimum reliability needs. On September 23, 2022, the CPUC issued a Ruling that finds based on the investigation analysis, that the Aliso CanyonNatural Gas Storage Facility is needed to maintain the reliability of the natural-gas system and to help stabilize gas andelectric rates until other resources are available to serve the Los Angeles Basin. In the same Ruling, the CPUC soughtcomments on a Staff Proposal presenting a framework to eliminate the need for Aliso Canyon by increasing non-gas-firedelectricity generation and storage, building electrification, and energy efficiency. The proposal quantifies the current needfor Aliso Canyon and estimates an annual increase of 1,084 MW of non-gas-fired electric generation capacity to reliablyserve all energy demand without the use of Aliso Canyon by 2027. Because natural gas and electricity systems anddemands are constantly evolving, this proposal suggests a biennial assessment where staff from the CPUC and CECupdate supply and demand information and consider whether gas demand reductions are on track with proposed targets.If not, staff will consider whether those targets should be adjusted. If gas demand is declining on pace to meet or exceedtargets, staff would recommend whether the maximum storage inventory at Aliso should be reduced. This process wouldcontinue every other year until Aliso Canyon is phased out.In winter 2022-23, California and the Western U.S. experienced historically high natural gas prices due to widespread,below-normal temperatures; high natural gas consumption; pipeline constraints; reduced natural gas flows; and lowstorage inventories. On August 31, 2023, the CPUC approved an increase to the maximum storage level allowed at AlisoCanyon from 41.16Bcf up to the safety limit set by CalGEM of 68.6Bcf. The decision allows more natural gas to be injectedand stored at Aliso Canyon to help secure energy reliability and protect against high natural gas and electric prices. Thedecision will not impact progress in proceeding towards phasing out the need for Aliso Canyon. SENATE BILL (SB) 859 – “BUDGET TRAILER BILL” – BIOMASS MANDATE In the final two days of the 2015-2016 legislative session, a “budget trailer bill” on how to spend cap-and-trade funds wasamended to include a biomass procurement mandate for local publicly-owned utilities serving more than 100,000customers. These utilities would be required to procure their pro-rata share of the statewide obligation of 125 MW basedon the ratio of the utility’s peak demand to the total statewide peak demand from existing in-state bioenergy projects for atleast a five-year term. On September 14, 2016, the Governor of California signed SB 859 into law.On October 13, 2016, the CPUC adopted Resolution E-4805, which established that the POUs be allocated 29 MW of the125 MW statewide mandate. The City determined that their obligated share would be 1.3 MW to meet the mandate. It isexpected that the City’s proportion of these facilities will be counted towards the Electric Utility’s Renewable PortfolioStandard (RPS) goals.In 2017, the affected POUs consisting of the cities of Anaheim, Los Angeles, and Riverside, Imperial Irrigation District,Modesto Irrigation District, Sacramento Municipal Utility District, and Turlock Irrigation District decided it would bebeneficial to procure a contract together for economies of scale. This was accomplished by utilizing SCPPA to issue aRequest for Proposal on behalf of all the affected POUs, since four of the seven POUs affected are existing SCPPAmembers.In January 2018, the Riverside Board and City Council approved the City’s five-year Power Sales Agreement with SCPPAfor 0.8 MW from the ARP-Loyalton biomass project. On April 20, 2018, the facility declared commercial operation.On September 21, 2018, the Governor signed into law SB 901, which primarily focuses on strengthening California’s abilityto prevent and recover from catastrophic wildfires such as via forest management activities, updating requirements formaintenance and operations of utility infrastructure, assessing GHG emissions impact, and protecting ratepayers. The billalso included a clause for certain biomass contracts that were procured or operating in 2018 and set to expire on or beforeDecember 31, 2023 to be offered a contract extension. The Electric Utility is required to “seek to amend the contract toinclude, or seek approval for a new contract that includes, an expiration date 5 years later than the expiration in thecontract”. Although there is no enforcement mechanism, the ARP-Loyalton biomass project meets the above criteria andfeedstock requirement referenced in SB 901 and SB 859. The Electric Utility had been working with ARP-Loyalton tocomply with SB 901, but production generation from the project site ceased in early January 2020. In late February 2020,ARP-Loyalton filed for Chapter 11 bankruptcy. Sale of the project was approved by the court to a new owner on April 30,2020. The term of the Agreement ended on April 19, 2023, fulfilling the regulatory requirements, and on April 30, 2024, thecourts approved the bankruptcy filing and associated settlement, which reimbursed the contractors for all the legal feesassociated with the bankruptcy.24MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISOn February 24, 2020 and March 17, 2020, Riverside's Board and City Council, respectively, adopted a five-year PurchaseAgreement with Roseburg Forest Products Co. for 0.5 MW in capacity to fulfill the remaining MW share of the mandate.On February 16, 2021, Roseburg declared commercial operation.SENATE BILL (SB) 350 – CLEAN ENERGY AND POLLUTION REDUCTION ACT OF 2015 SB 350, enacted in 2015, consists of a multitude of requirements to meet the Clean Energy and Pollution Reduction Act of2015. The primary components that affect the Electric Utility are: 1) the increased mandate of the California RPS to 50%by December 31, 2030, 2) doubling of energy efficiency savings by January 1, 2030, and 3) providing for thetransformation of the CAISO into a regional organization. In addition, there is a specific integrated resource planningmandate embedded in the bill that applies to the 16 POUs that have an annual electrical demand exceeding 700 GWhover a 3-year average, which includes the Electric Utility.The bill also requires that an updated RPS Procurement Policy must be approved and adopted before January 1, 2019and be incorporated into the Electric Utility’s Integrated Resource Plan (IRP). An Updated 2018 Renewable EnergyProcurement Policy was adopted by the Board and City Council on September 10, 2018 and October 9, 2018, respectively.In parallel, on or before January 1, 2019, the governing board of the Electric Utility must adopt an IRP and a process forupdating the plan at least once every 5 years. The IRP must address specific topics such as energy efficiency and demandresponse resources, transportation electrification, GHG emissions, energy storage resources, enhanced distributionsystems and demand-side management, etc. The IRP must be submitted to the CEC for review, of which the CEC willcheck if the statutory requirements have been met and will adopt guidelines to govern the submission of the IRPinformation. On August 9, 2017, the CEC adopted the POU IRP Submission and Review Guidelines.On September 30, 2017, the Governor signed SB 338, which requires that the governing board of local POUs consider aspart of the IRP process the role of existing renewable generation, grid operational efficiencies, energy storage, energyefficiency, and distributed energy resources in meeting the energy and reliability needs of each utility during the hours ofpeak demand. On August 1, 2018, the CEC adopted a Second Edition of the POU IRP Submission and Review Guidelinesto include the requirements of SB 338. On October 3, 2018, the CEC adopted an amendment to the second editionguidelines to include the CARB’s GHG emission reduction planning targets for IRPs.On November 26, 2018 and December 11, 2018, the Board of Public Utilities and City Council, respectively, adopted theElectric Utility’s 2018 Integrated Resource Plan. The IRP and additional submittal requirements were submitted to the CECon December 18, 2018. In April 2019, the CEC issued their Staff Paper Review of the Electric Utility’s IRP, as well as theCEC Executive Director’s Determination Letter finding the Electric Utility to be consistent with the requirements of SB 350.The adoption of this determination occurred at the CEC Business meeting on August 14, 2019.For the 5-year IRP update cycle mandated by SB 350, on August 5, 2022, the CEC published a Draft Revised Third Editionof the POU IRP Submission and Review Guidelines to reflect the SB 100 RPS procurement target of 60 percent of retailsales by 2030 and extend the IRP forecast horizon from 2030 to 2045. The Electric Utility completed an updated IRP asper the guidelines, and on April 8, 2024 and June 11, 2024, the Board of Public Utilities and City Council, respectively,adopted the Electric Utility's 2023 Integrated Resource Plan. The IRP and additional submittal requirements weresubmitted to the CEC on June 12, 2024. The Electric Utility is awaiting the CEC's review of its 2023 IRP.The CEC continues to host various workshops on different components of the SB 350 requirement and the Electric Utilityhas been monitoring its outcome.ASSEMBLY BILL (AB) 1110 AND SENATE BILL (SB) 1158 - LEGISLATION RELATING TO GREENHOUSEGAS EMISSIONS REPORTING FOR POWER RESOURCE DISCLOSURE On September 26, 2016, AB 1110 was signed into law requiring GHG emissions intensity data and unbundled renewableenergy credits (RECs) to be included as part of the retail suppliers’ power source disclosure (PSD) report and powercontent label (PCL) to their customers. GHG emissions intensity factors will need to be provided for all retail electricityproducts. The inclusion of this new information requirement on the PCL will begin in 2021 for calendar year 2020 data. Inaddition to still being required to post the PCL on the city website, the bill also reinstated the requirement that the PCLdisclosures must be mailed to the customers starting in 2017 for calendar year 2016 data unless customers have opted forelectronic notifications. In accordance with this requirement, Riverside reinstated the inclusion of printed disclosures of thePCL with its September 2017 bills to the customers.In 2017, the CEC began hosting workshops on the GHG emissions disclosure requirements and initiated the rulemakingprocess of updating their PSD regulations. A pre-rulemaking phase also began that included an implementation proposal25MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC25 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISon AB 1110. The legislation requires the CEC to adopt guidelines by January 1, 2018. In early 2018, the CEC provided anupdate to their 2017 pre-rulemaking activities and proposed changes to the regulations and reports, but additionalworkshops were needed. In March 2019, the last pre-rulemaking workshop was held by the CEC, with the intent to beginthe formal rulemaking in May, but was delayed until September 2019. On December 11, 2019, the CEC adopted theupdated PSD regulations, which changed the timing of the inclusion of the GHG emissions intensity data to be included inthe PCL starting in 2021 for calendar year 2020 data. The adoption of the updated PSD regulations and how the additionalGHG emissions intensity information would be conveyed to customers in the PSD report and PCL was approved on May 4,2020. The most notable changes to the report and label are the addition of the GHG emissions intensity and how certainenergy resources would be conveyed to the customers to meet the AB 1110 requirement.On September 16, 2022, Senate Bill (SB) 1158 was signed into law which requires, beginning January 1, 2028, every retailsupplier to annually report to the CEC information concerning electricity supply used to serve load, including the retailsupplier's hourly sources of electricity and the emissions of GHG associated with those sources of electricity. The bill alsorequires the CEC to share and publish the information annually on its website in an aggregated summary. The CEC isrequired to adopt rules to implement these reporting requirements on or before July 1, 2024. The CEC initiated the formalrulemaking period on May 17, 2024 by releasing an initial 45-day language package and hosted a rulemaking workshop onJuly 11, 2024 to solicit feedback on the proposed changes. It is anticipated that the CEC will be releasing an additional 45-day language package in Fall 2024. Riverside continues to monitor upcoming workshops and draft regulations for anyimpacts to the utility’s reporting and portfolio of resources.ASSEMBLY BILL (AB) 398 – GHG CAP-AND-TRADE PROGRAM EXTENSION AB 398 was signed on July 25, 2017 and approved extending the GHG cap-and-trade program to December 31, 2030,which was originally implemented under AB 32. This bill was also a companion bill to AB 617 as part of a legislativepackage that will be discussed further below. In addition, AB 398 required the CARB to update their scoping plan no laterthan January 1, 2018. AB 398 also requires all adopted GHG rules and regulations to be consistent with this plan. On July27, 2017, the CARB approved the 2016 Cap-and-Trade Amendments, which includes the Electric Utility’s 2021-2030allowance allocations it will receive each year. The Electric Utility’s allowance allocations should be sufficient to cover all ofits 2021-2030 direct compliance obligations.Initially, it was unclear under AB 398 whether the Electric Utility would be required to consign 100% of its allowances to themarket and then purchase allowances to fulfill its compliance obligations. Since the start of the Cap-and-Trade program in2012, POUs have been able to directly assign allowances for compliance. However, in 2017, the CARB announced theywere reconsidering this provision. In early 2018, after much discussion and collaboration with the CARB in which the POUsdemonstrated that they continue to include the price of GHG emissions in the cost of energy, it was agreed that the POUswould not be forced to consign their allocated direct-compliance allowances to auction. Other unknown components of thelaw include the banking provisions and the specific GHG revenue spending requirement for revenues generated from thesale of excess allowances. In June 2021, the CARB began focus area discussion workshops as part of the next iteration of the Scoping Plan Updateon four areas: 1) electricity sector, 2) transportation sector, 3) equity and environmental justice, and 4) natural and workinglands. On June 8, 2021, the CARB hosted a workshop series to commence development of the 2022 Scoping Plan Updateto Achieve Carbon Neutrality by 2045. Starting in July 2021 and onward, a series of technical workshops were hosted tocover various topics and sectors within the Scoping Plan. On December 15, 2022, the CARB Board unanimously adoptedthe 2022 Scoping Plan Update. The Scoping Plan focuses on laying out the path to achieving carbon neutrality andreducing anthropogenic GHG emissions by 85 percent below 1990 levels no later than 2045. The 2022 Scoping Planincludes decarbonization through the electrification of transportation and buildings which will increase the transportationand generation needs of the Electric Utility. The Scoping Plan also states that storage and demand-side management willbe essential to maintaining reliability as more renewables are incorporated into the electric grid.On July 27, 2023, the CARB held a workshop on the potential amendments to the cap-and-trade regulation. The CARB isagain proposing the requirement for consignment of POU allocations, which would add significant cost uncertainty intoenergy pricing and require the Electric Utility to purchase allowances from auction using alternative ratepayer funds.Potential impacts also include a decrease of annual allowance allocations and impacts to the Mandatory ReportingRequirement (MRR). The CARB has shown a particular interest in ensuring that allowance value targets low-income andpriority communities. The CARB has continued to hold public workshops throughout 2023 and 2024 to solicit feedback onpotential amendments. It is anticipated that the formal rulemaking will begin in late 2024 with the goal of the newregulations becoming effective early 2025. The Electric Utility will continue to monitor the outcome and impacts of theupcoming regulations on its service territory and ratepayers.26MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISASSEMBLY BILL (AB) 617 – AIR QUALITY MONITORING AB 617 was signed on July 26, 2017 and was part of a legislative bill package with AB 398, which authorized the extensionof the Cap-and-Trade Program in the State. AB 617 addresses the disproportionate impacts of air pollution in areasimpacted by a combination of economic, health, and environmental burdens. These burdens include combinations ofpoverty, high unemployment, health conditions such as asthma and heart disease, air and water pollution, and hazardouswastes. Both the CARB and local air districts are required to take specific actions to reduce air pollution and toxic aircontaminants from commercial and industrial sources, including from electricity-generating facilities. The bill required theCARB, by October 1, 2018, to prepare a statewide monitoring plan regarding technologies and reasons for monitoring airquality and, based on that plan, identify the highest priority locations for the deployment of community level air monitoringsystems. Local air districts are required to deploy the air monitoring systems in the specified communities by July 1, 2019.Additional locations for the deployment of the systems will be identified annually by the CARB beginning January 1, 2020.The CARB is also required to provide grants to community-based organizations for technical assistance and to supportcommunity participation in the programs. In turn, this effort would require the local air district of the selected community toadopt a community emissions reduction program.Additionally, AB 617 requires the CARB to develop uniform reporting standards for criteria air pollutants and toxic aircontaminants for specific uses, including electricity-generating facilities. Air districts are to adopt an expedited schedule forimplementing best available retrofit control technologies for the uses, while the CARB will identify these technologies.This bill affects the City and the Electric Utility by imposing additional reporting requirements, particularly on power plants,and potentially adding or improving air monitoring systems in selected communities located within the City of Riverside.For Riverside, the local air district is the Southern California Air Quality Management District (“SCAQMD”). The CARB andSCAQMD have held and continue to hold community meetings to implement the required elements of AB 617. Preliminarydiscussions and proposals have already been conveyed by community members from the City as well as from theUniversity of California, Riverside proposing areas for community air monitoring and planning. The City and Electric Utilityare monitoring the progress of the community meetings and the two proposed areas for any impacts.ASSEMBLY BILL (AB) 802 – BUILDING ENERGY USE BENCHMARKING AND PUBLIC DISCLOSUREPROGRAM On October 8, 2015, AB 802 was signed into law creating a new statewide building energy use benchmarking and publicdisclosure program for the State of California. The bill requires California utilities to maintain records of energy usage datafor all buildings (i.e., commercial and multifamily buildings over 50,000 square feet gross floor area) for at least the mostrecent 12 months. Beginning January 1, 2017, utilities are required to deliver or provide aggregated energy usage data fora covered building, as defined, to the owner, owner’s agent or operator upon written request. The Electric Utility providesconsumption data for buildings meeting the legislative requirement upon owners’ written request. The CEC adoptedregulations on October 11, 2017 and approved the regulation action to be effective on March 1, 2018. Building owners arerequired to report this information annually beginning on June 1, 2018.SENATE BILL (SB) 48 – BUILDING ENERGY SAVINGS ACTOn October 7, 2023, the Governor signed into law the Building Energy Savings Act (SB 48). This bill requires the CEC, inconsultation with the CARB, CPUC, and Department of Housing and Community Development, on or before July 1, 2026,to develop a strategy for using the energy usage data collected from the benchmarking and disclosure program developedthrough AB 802. The CEC intends to develop a report that reflects the strategy and recommendations to track andmanage the building energy usage and associated GHG emissions to achieve the State's equity, energy and emissiongoals, targets, and standards. The bill requires the CEC to submit the strategy and recommendations to the Legislature onor before August 1, 2026.On July 31, 2024, the CEC held a workshop to kick off the development of the California Building Energy PeformanceStrategy Report to also include recommendations for further legislative action. The Electric Utility will continue to monitorthe progress of the report for impacts on its service territory and ratepayers.27MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC27 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISSENATE BILL (SB) 100 – THE 100 PERCENT CLEAN ENERGY ACT OF 2018 On September 10, 2018, the Governor signed into law the 100 Percent Clean Energy Act of 2018 (SB 100). This bill furtherincreases the RPS goals of SBX1-2 and SB 350, while maintaining the 33% RPS target by December 31, 2020, butmodifying the future RPS percentages to be 44% by December 31, 2024, 52% by December 31, 2027, and 60% byDecember 31, 2030. The current end goal of SB 100 is to have 100% of the state's retail electricity supply generated froma mix of RPS-eligible and zero-carbon resources by December 31, 2045.The CEC is required to establish appropriate multi-year compliance periods for all subsequent years after 2030 that willrequire POUs to procure not less than 60% of retail sales from renewable resources. In September 2019, the CEC beganconducting pre-rulemaking workshops to discuss potential amendments to the RPS Enforcement Procedures for POUsthat would incorporate the SB 100 mandates. In addition, POUs will need to include the increased requirements in theirfuture IRP. On December 1, 2020, the CEC released the third 15-day language for the RPS Enforcement Procedures forPOUs and adopted it at the December 22, 2020 CEC Business Meeting. It was approved by the Office of AdministrativeLaw (OAL) and made effective July 12, 2021. The updated procedures clarify the interim targets for each year and thatcompliance periods beginning on and after January 1, 2031, shall be three years in length starting on January 1 andending on December 31. For each compliance period beginning on or after January 1, 2031, a POU shall demonstrate ithas procured electricity products within the compliance period sufficient to meet or exceed an average of 60 percent of thePOU's retail sales over the three calendar years of the compliance period.On December 4, 2020, the CEC issued a draft SB 100 Joint Agency Report, presented by the CEC with the CARB andCPUC. The joint agency report is intended to inform policy and planning, which is required to be presented to thelegislature every four years starting on January 1, 2021. The final report was published by the CEC and joint agencies onMarch 15, 2021. On August 22, 2023, the CEC, the CARB, and CPUC held a joint workshop to discuss findings andrecommendations from the 2021 SB 100 Joint Agency Report and the plan to address these findings andrecommendations as the 2025 SB 100 Joint Agency Report is being developed. In 2024, the CEC began hostingworkshops to discuss demand scenarios, as well as inputs and assumptions, for use in the 2025 SB 100 Joint AgencyReport. The final report is expected to be adopted in late 2024. Riverside will continue to monitor the outcome and impactsof any upcoming workshops and regulations in meeting the new requirements.SENATE BILL (SB) 1028, SB 901 AND ASSEMBLY BILL (AB) 1054 – LEGISLATION RELATING TOWILDFIRES On September 24, 2016, Governor Brown signed into law SB 1028, which requires each POU, IOU and electriccooperative to construct, maintain, and operate its electrical lines and equipment in a manner that will minimize the risk ofcatastrophic wildfire posed by those electrical lines and equipment.SB 901, which was passed at the end of the 2017-2018 biennium session of the California State Legislature and signed bythe Governor on September 21, 2018, is meant to address the Governor’s and legislative leaders’ desire to addressresponse, mitigation, and prevention of wildfires. SB 901 requires the Electric Utility to prepare before January 1, 2020 andannually thereafter, a wildfire mitigation plan (WMP) that includes specified information and elements. The Electric Utilitymust present its WMP in an appropriately noticed public meeting and accept comments on the plan from the public, otherlocal and state agencies, and interested parties, and to verify that the plan complies with all applicable rules, regulations,and standards, as appropriate. In addition, the Electric Utility must contract with a qualified independent evaluator to reviewand assess the comprehensiveness of its plan. The report of the independent evaluator must be made available on theElectric Utility’s website and presented at the local governing board’s public meeting.On July 12, 2019, the Governor signed into law AB 1054 and AB 111, which establishes the California Wildfire SafetyAdvisory Board (WSAB), adds an additional process requirement for review of wildfire mitigation plans, and establishes awildfire fund. In addition to the Electric Utility presenting its WMP to its local governing board by January 1, 2020, theElectric Utility must submit it to the new advisory board by July 1, 2020 and provide annual updates each year thereafter.Additionally, the Electric Utility is required to submit a comprehensive WMP at least once every three years.The City fully complied with AB 1054 and the City Council formally adopted the Wildfire Mitigation Plan on December 17,2019. Following City Council adoption, this approved plan was also submitted to the WSAB on May 6, 2020, as required.28MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISOn December 9, 2020, the WSAB completed their review of all publicly-owned utilities' initial WMPs and issued anadvisory opinion applicable to all POUs. It identified several themes that all POUs were requested to address and were notrequired to incorporate the recommendations as part of the next annual WMP update. Instead, POUs were asked torespond to a matrix of questions to be submitted at the same time as the next update of the WMP. The matrix is notrequired to be presented to the public utilities' governing boards.On June 14, 2021, the Electric Utility presented the updated 2021 WMP to its Board and received a recommendation thatthe City Council approve the 2021 Riverside Public Utilities WMP annual update for submittal to the WSAB by July 1,2021. During the Board meeting, staff identified updates to the WMP that would allow the Electric Utility to better respondto the WSAB's advisory opinion that had not been incorporated into the WMP. Instead of bringing it before the City Councilfor approval as is, staff opted to remove the item from consideration in order to provide an updated 2021 Riverside PublicUtilities WMP to the Riverside Board for approval again. The update to the 2021 Riverside Public Utilities WMP wasapproved on September 27, 2021 and October 12, 2021 by the Riverside Board and City Council, respectively.On June 27, 2022, the Riverside Board approved the 2022 WMP which was then submitted to the WSAB on June 30,2022. On October 17, 2022, the WSAB issued a guidance advisory opinion for the 2023 WMP for electric POUs and ruralelectric cooperatives. The advisory opinion included general guidance that applied to all POUs, specific guidance for eachPOU, and a template with instructions for preparing 2023 plans. All guidance was incorporated into Riverside’s 2023WMP. The 2023 WMP included the steps, programs, policies, and procedures implemented by the Electric Utility toreduce wildfire risks and minimize impacts to customers. As required by PUC Section 8387, a qualified independentevaluator was contracted to review and assess the 2023 WMP for comprehensiveness. The independent evaluatorprovided feedback on the plan, which the Electric Utility incorporated by including additional details to further clarify theElectric Utility’s wildfire mitigation measures. Afterwards, the independent evaluator concluded that the Electric Utility’s2023 WMP was sufficient in meeting the requirements for comprehensiveness. On June 26, 2023 and July 18, 2023, the2023 WMP and independent evaluator’s findings were presented to the Riverside Board and City Council, respectively.The 2023 WMP was submitted to the WSAB on July 19, 2023.The 2024 WMP was not required to be a comprehensive revision and therefore did not require an independent evaluatorreview. On June 10, 2024, the Riverside Board recommended approval of the 2024 WMP and on June 18, 2024, the CityCouncil approved the 2024 WMP. The 2024 WMP was submitted to the WSAB on July 1, 2024.For the wildfire fund, only voluntarily participating IOUs are eligible for claims arising from a covered wildfire. The POUsare not required nor able to join due to concerns and issues over complications of funding as a public entity. The bills donot address existing legal doctrine relating to utilities’ liability for wildfires. However, any future legislation that addressesCalifornia’s inverse condemnation and strict liability issues for utilities in the context of wildfires could be significant for theElectric Utility. Riverside is regularly engaged with the current WSAB meetings and updates, continues to partner with theRiverside Fire Department and diligently monitor the outcome and impacts of any upcoming legislation and regulations onits service territory and ratepayers.ASSEMBLY BILL (AB) 205 – ON-CALL RESOURCES AND ENERGY STORAGEOn June 30, 2022, AB 205 was signed into law to address several energy topics but more specifically, on-call emergencysupply and load reduction for the state’s electrical grid during extreme events to reduce the risk of blackouts. AB 205requires the CEC to implement and administer the Distributed Electricity Backup Assets (DEBA) Program to incentivize theconstruction of cleaner and more efficient distributed energy assets and the Demand Side Grid Support (DSGS) Programto incentivize dispatchable customer load reduction and backup generation operation to be on-call for extreme events. The initial DSGS program and guidelines launched in the Summer of 2022 and concluded October 2022. On July 26,2023, the CEC adopted the second edition of the DSGS guidelines, which made the program effective immediately. OnMay 8, 2024, the CEC adopted the DSGS Guidelines, Third Edition. Through the program, participating customers receivea financial incentive for on-call load reduction during extreme events and the Electric Utility receives reimbursement foradministrative costs to facilitate customer participation. The funding for the DSGS program was authorized by AB 205 andfurther expanded by AB 102 (signed on July 10, 2023), which stated the funding would be available for five years until June30, 2027. On May 13, 2024 and June 11, 2024, the recommendation for the Electric Utility to allow customers to participatein a non-utility sponsored demand response program under the CEC DSGS state program was approved by the RiversideBoard and City Council, respectively. The Electric Utility has begun authorization of enrolling customers in the CEC DSGSprogram, but no extreme events have been called upon by the CEC for this year.On January 27, 2023, the CEC held a workshop to discuss the DSGS program and the DEBA program. Information fromthis meeting was used to inform the development of the DEBA program. Proposed DEBA guidelines were released on29MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC29 ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISAugust 11, 2023, and were approved on October 18, 2023. The guidelines set aside 25% of program funding for projectsin POU territories, which would be awarded through grant funding opportunity solicitations. In December 2023, the firstDEBA grant funding opportunity was released for bulk grid asset enhancements focused on grid reliability. This programcould potentially provide funding to the Electric Utility for additional bulk grid assets and/or distributed resources.The Electric Utility will continue to monitor upcoming workshops and regulations for funding opportunities and any impactson its service territory and ratepayers.ASSEMBLY BILL (AB) 209 – ENERGY AND CLIMATE CHANGEOn September 6, 2023, AB 209 was signed into law authorizing several energy programs to address climate change. Oneprogram is the Equitable Building Decarbonization Program. The program provides funding for a Statewide Direct InstallProgram, Tribal Direct Install Program, a Statewide Incentive Program, and provides support for existing programs. Thisprogram must serve under-resourced communities and can fund eligible measures such as heating and cooling, buildingenvelope retrofits, water heating, cooking, and more. The program guidelines were adopted on October 18, 2024, and theprogram administrators were selected in August 2024. The program is expected to rollout to initial communities in late2024 to early 2025.AB 209 also established directives for allocating general funds to provide incentives for eligible residential customers,including publicly owned utility (POU) customers, for the Self-Generation Incentive Program (SGIP). SGIP providesincentives to support existing, new, and emerging distributed energy resources installed on the customer’s side of theutility meter. Qualifying technologies include wind turbines, fuel cells, advanced energy storage systems and more. On July10, 2023, the Governor approved Senate Bill (SB) 123, clarifying that SGIP incentives are eligible for low-incomeresidential customers who install behind-the-meter energy storage or photovoltaic systems. It also clarified that theseincentives are available to POU customers.Another program under AB 209 that the CEC must establish and administer is the Hydrogen Program to provide financialincentives to in-state hydrogen projects for the demonstration or scale-up of the production, processing, delivery, storage,or end use of clean hydrogen. The CEC held a workshop in December 2022 to provide an overview of the Clean HydrogenProgram and the proposed program scope, funding areas, and project requirements. On May 19, 2023, the CEC releaseda draft solicitation concept for large-scale centralized production to solicit public feedback. On May 23, 2023, the CECreleased the “Cost Share for Federal Clean Energy Funding Opportunities” competitive solicitation, which is ongoing. InMay 2024, Governor Newsom released the 2024-2025 Revised State Budget Proposal, which called for reducing theClean Hydrogen Program funding to $40 million and delaying the majority of funding until fiscal year 2025-2026. The Electric Utility will continue to monitor the development of these programs to determine opportunities and impacts onits service territory and ratepayers.FIVE-YEAR ELECTRIC RATE PLAN On September 19, 2023, the City Council approved a new five-year Electric Rate Plan, which includes system averageannual rate increases. The first rate increase was effective January 1, 2024 with the following four years effective onJanuary 1 of each year. The approved five-year Electric Rate Plan includes annual reviews of the adopted rates by CityCouncil. The system average rate increases effective January 1, 2024 through 2026 are 7.0%, followed by system averagerate increases of 2.0% in years four and five. The Electric Rate Plan was designed to provide financial stability and correctthe imbalance of costs versus revenue recovery.ECONOMIC DEVELOPMENT AND GREEN INITIATIVES The City of Riverside has a long history of valuing sustainability and ensuring economic development. Recent efforts forsustainability began in 2001 when the City began using light-emitting diodes in all City traffic signals to reduce electricityusage. Today, the City remains committed to environmental issues and serves as a state leader in sustainability.The City’s first sustainability policy statement was adopted in 2007 and ultimately led to the adoption of three Green ActionPlans, the latest of which was adopted in 2012. Most recently, the City adopted the Envision Riverside 2025 Strategic Planin October 2020. This plan incorporates sustainability throughout as a cross cutting value and environmental stewardshipas one of six priority areas for the City. Additional adopted policies can be found in the City’s General Plan 2025 (2007),the Environmentally Preferable Purchasing Policy (2009), the Food and Agriculture Policy Action Plan (2015) and theRiverside Restorative Growthprint (2016). The City is in the process of adopting a new General Plan (GP) and ClimateAction and Adaption Plan (CAAP). Once these documents are completed, they will serve in place of the previous GreenAction Plans and Riverside Restorative Growthprint.30MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC ELECTRIC UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISThe City hosts community-wide Green Riverside Leadership Summits. Since 2012, summits have been held every 2 to 3years. Events in 2012 and 2019 were in partnership with the University of California Riverside. Events in 2014 and 2016were conducted as part of the community-led Riverside Green Festival and Summit.The City has received numerous recognitions for its sustainability programs and initiatives. In 2009, the CaliforniaDepartment of Conservation named Riverside its first "Emerald City" in recognition for its sustainable green initiatives andcommitment to help the state achieve multiple state environmental priorities. The City was honored in 2016 with the GreenCommunity Award from Audubon International, recognizing Riverside for its ongoing sustainability initiatives. In addition,the City received the 2016 Sustainable Communities Award from the Green California Leadership Summit for its ongoingcommunity-wide sustainability projects and programs that create environmental awareness and action throughout thecommunity, including business, government and private citizens. The Green California Leadership Summit againrecognized the City in 2018 with its Leadership Award for the City Green Fleet Program. Additionally, in 2022, Riversidewas ranked #1 in North America for the Green Fleet Award by the NAFA Fleet Management Association.The Utility hosted its inaugural community Earth Day celebration in 2022. The day provided customers with informationand tips on energy efficiency and water conservation best practices. There were electric vehicle demonstrations andexperts on hand to advise on how to incorporate native plants in local landscapes. Earth Days in 2023 and 2024 were bothmarked by community celebration days, hosted in collaboration with the City’s Insect Fair. The RPU team was able toexpand on its messaging and outreach by hosting several booths and the Wyland interactive truck, which provided ahands-on experience for attendees to learn in detail about water conservation and energy efficiency, and the changes theycould make towards achieving these goals. The Electric Utility supports the local economy by offering some of the lowest commercial electric rates in SouthernCalifornia combined with attractive economic development electric discount rates to qualified new and expanded loadcustomers. These rate programs have helped create and retain over 3,600 jobs in the City since 2010. In late 2021, theUtility relaunched the commercial energy audit program, which provides Key Account customers with a comprehensiveenergy efficiency plan, a priority list of recommended energy efficiency measures, an estimated return on investment andapplicable utility incentives. To date, several key customers have utilized this program, which has delivered in excess of700,000 kWh annual savings so far. Audits for key account customers are in process, with more anticipated in the future.Beyond rate incentives, the Electric Utility also offers local businesses a comprehensive assortment of water and energyefficiency programs to improve building efficiency and reduce customer electric consumption. Fiscal year 2021-22commercial energy efficiency programs saved a total of 4.2 million kWh. Fiscal year 2022-23 saw increased energyefficiencies being realized, with almost 7.3 million kWh saved via RPU's programs. In fiscal year 2023-24, these numbersincreased and 8.1 million kWh of energy savings was made.All of these efforts support organizations and companies in meeting their sustainability goals. Most recently, the State ofCalifornia’s Air Resources Board relocated their Southern California headquarters to the City of Riverside. The campusopened in 2021 and is one of the largest and most advanced vehicle emissions testing and research facilities in the world.Additionally, the headquarters are LEED Platinum, the highest level awarded by the U.S. Green Building Council for theoverall sustainability and energy efficiency of a building. This facility, through a combination of on-site solar PV and a 100%renewable energy rate program through the utility, receives all of its power from non-carbon emitting resources.The City initiated an ambitious LED streetlight replacement program in 2016. The program will eventually replace all city-owned streetlights by 2026, resulting in approximately 10 million kWh saved annually along with substantially reducedmaintenance costs. Additionally, the Utility’s Energy, Water and Custom Energy technology grant programs continue toencourage local higher education institutions and business electric customers to submit proposals for potential grantfunding for important research projects that explore new and innovative ways to advance energy technology.These economic development and sustainability projects and programs put the Electric Utility on the cutting edge of jobcreation and resource efficiency, making the City a better place to live and do business.REQUESTS FOR INFORMATION This financial report is designed to provide a general overview of the Electric Utility’s finances. Questions concerning anyinformation provided in this report or requests for additional financial information should be addressed to the UtilitiesAssistant General Manager – Finance and Administration, Riverside Public Utilities, 3750 University Avenue, 5th floor,Riverside, CA 92501. Additional financial information can also be obtained by visiting www.RiversidePublicUtilities.com.31MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC31 ELECTRIC UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF NET POSITIONJune 30,2024June 30,2023ASSETS AND DEFERRED OUTFLOWS OF RESOURCES (in thousands)NON-CURRENT ASSETS: Capital assets:Utility plant, net of accumulated depreciation (Note 3) $624,143$645,617Capital assets, not depreciated (Note 3)152,320139,299Lease and subscription assets, net of amortization (Note 3)410405Total capital assets776,873785,321Restricted assets:Cash and investments at fiscal agent (Note 2) 48,53058,135Cash and cash equivalents at fiscal agent (Note 2) 127,743-Total non-current restricted assets176,27358,135Other non-current assets:Advances to Successor Agency Trust Fund1,5552,003Lease receivable (Note 13)11,06910,407Unamortized purchase power (Note 11) 11,02511,664Regulatory assets2,1091,573Total other non-current assets25,75825,647Total non-current assets978,904869,103CURRENT ASSETS:Unrestricted assets:Cash and cash equivalents (Note 2) 258,200247,831Accounts receivable, less allowance for doubtful accounts2024 ($1,929); 2023($3,351) 41,80537,260Accrued interest receivable1,6261,033Leases receivable (Note 13)1,3431,359Inventory1,4641,464Prepaid expenses3,8596,168Unamortized purchase power (Note 11) 664666Total unrestricted current assets308,961295,781Restricted assets: Cash and cash equivalents (Note 2) 58,24144,794Public Benefit Programs - cash and cash equivalents (Note 2)32,03329,152Public Benefit Programs receivable1,2211,070Total restricted current assets91,49575,016Total current assets:400,456370,797Total assets1,379,3601,239,900DEFERRED OUTFLOWS OF RESOURCES: Deferred outflows related to pension (Note 6) 31,01834,931Deferred outflows related to other postemployment benefits (Note 7)1,4981,592Changes in derivative values-1,571Loss on refunding2,1557,530Total deferred outflows of resources34,67145,624Total assets and deferred outflows of resources$1,414,031$1,285,524See accompanying notes to financial statements32FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF NET POSITIONJune 30,2024June 30,2023NET POSITION, LIABILITIES AND DEFERRED INFLOWS OF RESOURCES (in thousands)NET POSITION: Net investment in capital assets$230,789$254,225Restricted for:Regulatory requirements(Note 8) 34,26125,502Debt service (Note 8) 23,98119,332Unfunded accrued liability3,510-Public Benefit Programs32,48229,329Unrestricted183,511174,964Total net position508,534503,352LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (Note 4)712,106590,602OTHER NON-CURRENT LIABILITIES:Compensated absences (Note 5) 2,0651,889Net pension liability (Note 6) 44,22738,748Nuclear decommissioning liability (Note 10) 33,83838,646Other postemployment benefits liability (Note 7) 10,0499,420Derivative instruments (Note 4) -4,097Regulatory liability-4,675Lease liability (Note 13)162225SBITA liability (Note 13)467Total other non-current liabilities90,38797,707CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS: Accrued interest9,8165,083Public Benefit Programs payable750866Nuclear decommissioning liability (Note 10) 12,24410,227Current portion of long-term obligations (Note 4) 23,68022,633Total current liabilities payable from restricted assets46,49038,809CURRENT LIABILITIES:Accounts payable and other accruals21,28619,584Compensated absences (Note 5) 5,3355,589Customer deposits12,88111,734Unearned revenue762314Other postemployment benefits liability (Note 7)397417Lease liability (Note 13)132137SBITA liability (Note 13)5042Total current liabilities40,84337,817Total liabilities889,826764,935DEFERRED INFLOWS OF RESOURCES:Deferred inflows related to pension (Note 6) 1,8923,577Deferred inflows related to other postemployment benefits (Note 7)2,0382,266Lease related items (Note 13)11,74111,394Total deferred inflows of resources15,67117,237Total net position, liabilities and deferred inflows of resources$1,414,031$1,285,524See accompanying notes to financial statements33FINANCIAL STATEMENTS: ELECTRIC33 ELECTRIC UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITIONFor the Fiscal YearsEnded June 30,20242023(in thousands)OPERATING REVENUES: Residential sales$138,879$140,538Commercial sales77,85077,191Industrial sales130,519124,600Other sales5,2545,162Wholesale sales-2,043Transmission revenue39,93435,233Other operating revenue26,08924,403Public Benefit Programs11,32810,222Total operating revenues before uncollectibles429,853419,392Estimated uncollectibles, net of bad debt recovery(2,466)(475)Total operating revenues, net of uncollectibles427,387418,917OPERATING EXPENSES:Production and purchased power199,566195,914Transmission54,24868,052Distribution81,00568,057Public Benefit Programs8,1746,751Depreciation38,08138,189Amortization200214Total operating expenses381,274377,177Operating income46,11341,740NON-OPERATING REVENUES (EXPENSES): Investment (loss) income18,7155,952Interest expense and fiscal charges(25,934)(23,775)Gain on sale of assets429957Other3,5955,387Total non-operating revenues (expenses)(3,195)(11,479)Income before capital contributions and operating transfers out42,91830,261Capital contributions7,5539,854Transfers out - contributions to the City's general fund(45,289)(42,326)Total capital contributions and transfers out(37,736)(32,472)Change in net position5,182(2,211)NET POSITION, BEGINNING OF YEAR503,352505,563NET POSITION, END OF YEAR$508,534$503,352See accompanying notes to financial statements34FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF CASH FLOWS20242023(in thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Cash received from customers and users$424,286$430,913Cash paid to suppliers for goods and services(279,482)(290,354)Cash paid to employees for services(53,663)(56,730)Net cash provided/(used) by operating activities91,14183,829CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:Cash transfers out(45,289)(42,326)Payment receipt from advances to other funds448451Debt service payment on pension obligation bonds(5,118)(4,232)Other non-operating receipts3,2965,140Net cash provided/(used) by non-capital financing activities(46,663)(40,967)CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:Acquisition and construction of capital assets(27,366)(27,183)Principal paid on capital debt(17,515)(17,124)Interest paid on capital debt(23,600)(26,149)Payment to refunding escrow agent(134,114)-Contributions4,7014,951Proceeds from sales of capital assets1,0185,673Lease and subscription payments(241)(215)Proceeds from revenue bonds, including premium283,940-Bond issuance costs(4,588)-Net cash provided/(used) by capital and related financing activities82,235(60,047)CASH FLOWS FROM INVESTING ACTIVITIES:Income (loss) from investments18,1225,582Proceeds from/(purchase of) investment securities9,605(4,350)Net cash provided/(used) by investing activities27,7271,232Net increase/(decrease) in cash and cash equivalents154,440(15,953)CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $73,946 and$64,587 at June 30, 2023 and June 30, 2022, respectively, reported in restrictedaccounts)321,777337,730CASH AND CASH EQUIVALENTS, END OF YEAR (including $218,017 and $73,946 atJune 30, 2024 and June 30, 2023, respectively, reported in restricted accounts)$476,217$321,777See accompanying notes to financial statements35FINANCIAL STATEMENTS: ELECTRIC35 ELECTRIC UTILITY:FINANCIAL STATEMENTSSTATEMENT OF CASH FLOWS20242023(in thousands)RECONCILIATION OF OPERATING INCOME TO NET CASH PROVIDED BYOPERATING ACTIVITIES:Operating income (loss)46,11341,740Adjustments to reconcile operating income/(loss) to net cash provided/(used) byoperating activities: Depreciation38,08138,189Amortization200214(Increase) decrease in utility billed receivable(588)9,137(Increase) decrease in utility unbilled receivable(3,878)2,985(Increase) decrease in accounts receivable229732(Increase) decrease in prepaid items3,065679(Increase) decrease in deposits(116)(79)(Increase) decrease in inventory-(979)(Increase) decrease in intergovernmental receivable(306)(20)Increase (decrease) in accounts payable2,087(3,494)Increase (decrease) in accrued payroll173192Increase (decrease) in retainage payable(559)164Increase (decrease) in decommissioning liability(2,791)(4,438)Increase (decrease) in Public Benefit Programs payable(117)242Increase (decrease) in deposits payable1,147(154)Increase (decrease) in unearned revenue448(1,097)Increase (decrease) in compensated absences(78)278Increase (decrease) in net pension liability7,707(1,308)Increase (decrease) in OPEB liability475431Increase (decrease) in Public Benefit Program receivable(151)415Total adjustments45,02842,089Net cash provided/(used) by operating activities$91,141$83,829SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:Capital contributions - capital assets$2,852$4,903Increase (decrease) in fair value of investments-(529)See accompanying notes to financial statements36FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESThe Electric Utility exists under, and by virtue of, the City of Riverside (the City) Charter enacted in 1883. The ElectricUtility is responsible for the generation, transmission, and distribution of electric power for sale in the City. Theaccompanying financial statements present only the financial position and the results of operations of the Electric Utility,which is an enterprise fund of the City, and are not intended to present fairly the financial position and results of operationsof the City in conformity with generally accepted accounting principles. However, certain disclosures are for the City as awhole, since such information is generally not available for the Electric Utility on a separate fund basis. All amounts, unlessotherwise indicated, are expressed in thousands of dollars.BASIS OF ACCOUNTINGThe Electric Utility uses the accrual basis of accounting as required for enterprise funds with accounting principlesgenerally accepted in the United States of America as applicable to governments. The accounting records of the ElectricUtility are also substantially in conformity with the Uniform System of Accounts prescribed by the Federal EnergyRegulatory Commission (FERC). The Electric Utility is not subject to the regulations of the FERC.The Electric Utility distinguishes operating revenues and expenses from non-operating items. Operating revenues andexpenses generally result from providing services and producing and delivering goods in connection with an enterprisefund’s principal ongoing operations. The principal operating revenues of the Electric Utility are charges to customers forelectric sales and services. Operating expenses for the Electric Utility include the cost of electric sales and services,administrative expenses, and depreciation on capital assets. All revenues and expenses not meeting this definition arereported as non-operating revenues and expenses.IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENTSIn November 2016, the GASB issued Statement No. 83, Certain Asset Retirement Obligations (GASB 83). This Statementaddresses accounting and financial reporting for certain asset retirement obligations (AROs). An ARO is a legallyenforceable liability associated with the retirement of a tangible capital asset. This Statement establishes criteria for (1)determining the timing and pattern of liability recognition and a corresponding deferred outflow, (2) requires liabilityrecognition when it is incurred and reasonably estimable, and (3) requires ARO measurement to be based on the bestestimate of the current value of outlays expected to be incurred. If an ARO has been incurred but is not yet recognizedbecause it is not reasonably estimable, the government is required to disclose that fact and the reasons therefor. ThisStatement will enhance comparability of financial statements among governments by establishing uniform criteria forgovernments to recognize and measure certain AROs, including obligations that may not have been previously reported.This Statement is effective for reporting periods beginning after June 15, 2020. According to Clearwater Power Plant Asset Purchase and Sale Agreement dated March 3, 2010, the City of Riversidepurchased the Clearwater Power Plant (the “Plant”) from the City of Corona to own, operate, and pay all costs related tothe Plant and the assets, as set forth in the agreement. On August 26, 2010, Temporary Right of Entry Agreement wasmade and entered into between the City of Riverside (“Riverside”) and the City of Corona (“Corona”) in which Coronaleased the Corona Clearwater Cogeneration Facility (the “Property”) to Riverside for its operation and maintenance of theProperty. Riverside is responsible for plant decommissioning and site restoration related to the Plant. The ARO evaluationstudy to measure the obligation was completed in fiscal year 2019-2020. However, since Riverside does not have the finallease agreement with Army Corps to determine the life of the plant, a liability and deferred outflow will not be recorded infiscal year 2023-2024.The following new Governmental Accounting Standards Board (GASB) pronouncements were effective and have beenimplemented for fiscal year 2023-2024 audit: GASB Statement No. 99, Omnibus 2022 - This Statement provides clarification on previously issued Statements, includingthe classification and reporting of derivative instruments within the scope of Statement No. 53, Accounting and FinancialReporting for Derivative Instruments, that do not meet the definition of either an investment derivative instrument or ahedging derivative instrument; clarification of provisions in Statement No. 87, Leases, as amended, related to thedetermination of the lease term, classification of a lease as a short-term lease, recognition and measurement of a leaseliability and a lease asset, and identification of lease incentives; clarification of provisions in Statement No. 94, Public-Private and Public-Public Partnerships and Availability Payment Arrangements, related to (a) the determination of thepublic-private and public-public partnership (PPP) term and (b) recognition and measurement of installment payments andthe transfer of the underlying PPP asset; clarification of provisions in Statement No. 96, Subscription-Based InformationTechnology Arrangements, related to the subscription-based information technology arrangement (SBITA) term,classification of a SBITA as a short-term SBITA, and recognition and measurement of a subscription liability; extension of37NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC37 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED)the period during which the London Interback Offered Rate (LIBOR) is considered an appropriate benchmark interest ratefor the qualitative evaluation of the effectiveness of an interest rate swap that hedges the interest rate risk of taxable debt;accounting for the distribution of benefits as part of the Supplemental Nutrition Assistance Program (SNAP); disclosuresrelated to nonmonetary transactions; pledges of future revenues when resources are not received by the pledginggovernment; clarification of provisions in Statement No. 34, Basic Financial Statements—and Management's Discussionand Analysis—for State and Local Governments, as amended, related to the focus of the government-wide financialstatements; terminology updates related to certain provisions of Statement No. 63, Financial Reporting of DeferredOutflows of Resources, Deferred Inflows of Resources, and Net Position; and terminology used in Statement 53 to refer toresource flows statements.GASB Statement No. 100, Accounting Changes and Error Corrections - This Statement defines accounting changes aschanges in accounting principles, changes in accounting estimates, and changes to or within the financial reporting entityand describes the transactions or other events that constitute those changes. It prescribes the accounting and financialreporting for (1) each type of accounting change and (2) error corrections, and requires that (a) changes in accountingprinciples and error corrections be reported retroactively by restating prior periods, (b) changes to or within the financialreporting entity be reported by adjusting beginning balances of the current period, and (c) changes in accounting estimatesbe reported prospectively by recognizing the change in the current period. Refer to Note 12 for current year adjustmentsrelated to GASB Statement No. 100.USE OF ESTIMATESThe preparation of financial statements in conformity with accounting principles generally accepted in the United Statesrequires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenuesand expenses during a reporting period. Accordingly, actual results could differ from those estimates.REVENUE RECOGNITIONThe Electric Utility customers are billed monthly. Unbilled electric service charges, including Public Benefit Programs, arerecorded at year-end and are included in accounts receivable. Unbilled accounts receivable totaled $17,991 at June 30,2024, and $14,004 at June 30, 2023.An allowance for doubtful accounts is maintained for the Electric Utility and miscellaneous accounts receivable. Thebalance in this account is adjusted at fiscal year-end to approximate the amount anticipated to be uncollectible.ELECTRIC UTILITY PLANT AND DEPRECIATIONThe Electric Utility defines capital assets as assets with an initial, individual cost of more than five thousand dollars and anestimated useful life in excess of one year. Electric Utility plant assets are valued at historical cost or estimated historicalcost, if actual historical cost is not available. Costs include labor, materials, allocated indirect charges such as engineering,supervision, construction and transportation equipment, retirement plan contributions, and other fringe benefits.Contributed plant assets are recorded at their acquisition values as of the date of contribution. The cost of relatively minorreplacements is included in maintenance expense. Intangible assets that cost more than one hundred thousand dollarswith useful lives of at least three years are capitalized and are recorded at cost.Depreciation is provided over the estimated useful lives of the related assets using the straight-line method. The estimateduseful lives are as follows:Production plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................10-40 yearsTransmission and distribution plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................20-50 yearsGeneral plant and equipment................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-50 yearsIntangibles................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-10 years38NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)RESTRICTED ASSETSProceeds of revenue bonds yet to be used for capital projects, as well as certain resources set aside for debt service, areclassified as restricted assets in the Statements of Net Position because their use is limited by applicable bond covenants.Funds set aside for the nuclear decommissioning and regulatory requirements relating to greenhouse gas allowances arealso classified as restricted assets because their use is legally restricted to a specific purpose. Generally, the Electric Utilitywill first apply restricted resources when expenses are incurred for which both restricted and unrestricted resources areavailable.In January 1998, the Electric Utility began collecting a surcharge for Public Benefit Programs on customer utility bills. Thissurcharge is mandated by state legislation included in Assembly Bill 1890 and is restricted to various socially beneficialprograms and services. The programs and services include cost effective demand-side management services to promoteenergy efficiency and conservation and related education and information; ongoing support and new investments inrenewable resource technologies; energy research and development; and programs and services for low-income electriccustomers. The activity associated with the surcharge for Public Benefit Programs is reflected in the accompanyingfinancial statements on the Statements of Net Position, Statements of Revenues, Expenses and Changes in Net Position,and Statements of Cash Flows.CASH AND CASH EQUIVALENTSFor the Statements of Cash Flows, cash and cash equivalents include all unrestricted and restricted highly liquidinvestments with original purchase maturities of three months or less, and all bond construction proceeds available forcapital projects held at fiscal agent. Pooled cash and investments in the City’s Treasury represent monies in a cashmanagement pool. Such accounts are similar in nature to demand deposits, and are classified as cash equivalents for thepurpose of presentation in the Statements of Cash Flows.CASH AND INVESTMENTSThe Electric Utility’s cash and investments, except for funds required to be held by outside fiscal agents under theprovisions of bond indentures, which are administered by outside agencies, are invested in the cash and investment poolof the City.The Electric Utility values its cash and investments in accordance with provisions of GASB Statement No. 72, Fair ValueMeasurement and Application, which requires governmental entities to use valuation techniques that are appropriate underthe circumstances and for which sufficient data are available to measure fair value. The techniques should be consistentwith one or more of the following approaches: the market approach, the cost approach or the income approach. Valuationincludes a hierarchy of inputs with three distinct levels. Level 1 are quoted prices in an active market for identical assets;Level 2 inputs are significant other observable inputs; and Level 3 inputs are significant unobservable inputs. The ElectricUtility does not value any of its investments using level 3 inputs.City-wide information concerning cash and investments as of June 30, 2024, including authorized investments, fair valuemeasurement and application, custodial credit risk, credit and interest rate risk for debt securities and concentration ofinvestments, carrying amount and market value of deposits and investments can be found in the notes to the City’sfinancial statements in the City’s Annual Comprehensive Financial Report.CASH AND INVESTMENTS AT FISCAL AGENTSCash and investments maintained by fiscal agents are considered restricted by the Electric Utility. A portion is pledged ascollateral for payment of principal and interest on outstanding bonds and certain funds are set aside to decommission theElectric Utility’s proportionate share of Units 2 and 3 at SONGS. Further details regarding the jointly-owned projectSONGS can be found in Note 10. CalPERS's positive investment returns contributed to the reduction of the unfunded accrued liability (UAL); as a result,originally budgeted UAL payments were redirected to the Electric Utility's restricted cash and investments held at fiscalagent to aid the Electric Utility in long-term management of rising pension costs. See Notes 6 for further discussion relatedto the CalPERS pension plan, including UAL. 39NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC39 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)DESIGNATED CASH RESERVESThe Riverside Public Utilities Cash Reserve Policy establishes several designated cash reserves in the Electric Utility forstrategic purposes. Designated reserves are set aside for specific purposes determined by the Board of Public Utilities andCity Council. Designated reserves may be held for capital or operating purposes.Designated cash reserve balances as of June 30, 2024 and 2023 were as follows: Additional Decommissioning LiabilityReserve $10,885 and $8,644, Customer Deposits $5,014 and $4,948, Capital Repair and Replacement Reserve $2,336and $2,287, Electric Reliability Reserve $95,689 and $87,127, Mission Square Improvement Reserve $2,757 and $2,113,and Dark Fiber Reserve $5,556 and $4,801. The combined total for these reserves was $122,237 and $109,920 at June30, 2024 and 2023, respectively, and is included as a component of unrestricted cash and cash equivalents in theaccompanying Statements of Net Position.ADVANCES TO OTHER FUNDS OF THE CITYAdvances to Successor Agency Trust Fund have been recorded as a result of agreements between the Electric Utility andthe Successor Agency. The balances as of June 30, 2024 and 2023 are $1,555 and $2,003, respectively.DERIVATIVESThe Electric Utility accounts for derivative instruments using GASB Statement No. 53, Accounting and Financial Reportingfor Derivative Instruments (GASB 53). This Statement requires the Electric Utility to report its derivative instruments at fairvalue. Changes in fair value for effective hedges are to be reported as deferred inflows and outflows of resources on theStatements of Net Position. Changes in fair value of derivative instruments not meeting the criteria for an effective hedge,or that are associated with investments are to be reported in the non-operating revenues section of the Statements ofRevenues, Expenses and Changes in Net Position.The Electric Utility has determined that its interest rate swaps associated with variable rate obligations are derivativeinstruments under GASB 53. See Note 4 Long-Term Obligations for further discussion related to the Electric Utility’sinterest rate swaps.Various transactions permitted in the Electric Utility’s Power Resources Risk Management Policies may be consideredderivatives, including energy and/or gas transactions for swaps, options, forward arrangements and congestion revenuerights (CRR). GASB 53 allows an exception for the Statements of Net Position deferral hedges that meet the normalpurchases and normal sales exception. The Electric Utility has determined that all of its contracts including CRRs fallunder the scope of “normal purchases and normal sales” and are exempt from GASB 53.BOND PREMIUMS AND GAINS/LOSSES ON REFUNDINGBond premiums and gains/losses on refunding (including gains/losses related to interest rate swap transactions) aredeferred and amortized over the term of the new bonds using the effective interest method. Bonds payable are reportednet of the applicable bond premiums. Gains/losses on refunding are reported as deferred inflows or outflows of resources.CUSTOMER DEPOSITSThe City holds customer deposits as security for the payment of utility bills and design fee deposits for future constructionof electrical facilities. The Electric Utility’s portion of these deposits as of June 30, 2024 and 2023 was $12,881 and$11,734, respectively.COMPENSATED ABSENCESThe accompanying financial statements include accruals for salaries, fringe benefits and compensated absences due toemployees at June 30, 2024 and 2023. The Electric Utility treats compensated absences due to employees as an expenseand a liability of which a current portion is included in accounts payable and other accruals in the accompanyingStatements of Net Position. The amount accrued for compensated absences was $7,400 at June 30, 2024 and $7,478 atJune 30, 2023.Employees receive 10 to 25 vacation days per year based upon length of service. A maximum of two years vacationaccrual may be accumulated and unused vacation is paid in cash upon separation.40NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)COMPENSATED ABSENCES (CONTINUED)Employees primarily receive one day of sick leave for each month of employment with unlimited accumulation. Uponretirement or death, certain employees or their estates receive a percentage of unused sick leave paid in a lump sumbased on longevity.INSURANCE PROGRAMSThe Electric Utility participates in a self-insurance program for workers’ compensation and general liability coverage that isadministered by the City. The Electric Utility pays an amount to the City based on actuarial estimates of the amountsneeded to fund prior and current year claims and incidents that have been incurred but not reported. The City maintainsproperty insurance on most City property holdings, for a shared limit of $1 billion and $210 million to cover powergeneration facilities.City-wide information concerning risks, insurance policy limits and deductibles and designation of general fund balance forrisk for the year ended June 30,2024 may be found in the notes to the City’s financial statements in the City’s AnnualComprehensive Financial Report.Although the ultimate amount of losses incurred through June 30, 2024 is dependent upon future developments,management believes that amounts paid to the City are sufficient to cover such losses. Premiums paid to the City by theElectric Utility, including the Public Benefit Programs, were $2,469 and $2,058 for the years ended June 30, 2024 and2023, respectively. Any losses above the City’s reserves would be covered through increased rates charged to the ElectricUtility in future years.EMPLOYEE RETIREMENT PLANThe City contributes to the California Public Employees Retirement System (CalPERS), an agent multiple employer publicemployee defined benefit pension plan. CalPERS provides retirement and disability benefits, annual cost-of-livingadjustments, and death benefits to plan members and beneficiaries. CalPERS acts as a common investment andadministrative agent for participating public entities within the State of California. Benefit provisions and all otherrequirements are established by state statute and City ordinance.For purposes of measuring the net pension asset/liability and deferred outflows/inflows of resources related to pensionsand pension expense, information about the fiduciary net position of the City of Riverside California Public Employees’Retirement System plans (Plans) and additions to/deductions from the Plans’ fiduciary net position have been determinedon the same basis as they are reported by CalPERS. For this purpose, benefit payments (including refunds of employeecontributions) are recognized when due and payable in accordance with the benefit terms. Investments are reported at fairvalue. Further details of employee retirement plan can be found in Note6.OTHER POSTEMPLOYMENT BENEFITS (OPEB)OPEB refers to the benefits, other than pensions, that the City provides as part of an employee’s retirement benefits. Thenet OPEB liability is defined as the liability of employers contributing to employees for benefits provided through a definedbenefit OPEB plan that is administered through a trust. Further details for OPEB can be found in Note7.DEFERRED OUTFLOWS AND DEFERRED INFLOWS OF RESOURCESWhen applicable, the Statements of Net Position will report a separate section for deferred outflows of resources. Deferredoutflows of resources represent outflows of resources (consumption of net position) that apply to future periods and that,therefore, will not be recognized as an expense or expenditure until that time. Deferred outflows of resources consist ofchanges in derivative values, loss on refunding and deferred outflows related to pension and OPEB, which include pensioncontributions subsequent to measurement date, difference between actual and actuarial determined contribution, changesin assumptions and net differences between projected and actual earnings on pension plan investments.Conversely, deferred inflows of resources represent inflows of resources (acquisition of net position) that apply to futureperiods and that, therefore, are not recognized as an inflow of resources (revenue) until that time. Deferred inflows ofresources consist of lease related items, deferred inflows related to pension and OPEB, which include changes inassumptions, differences between expected and actual experience, and net differences between projected and actualearnings on pension plan investments.41NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC41 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)REGULATORY ASSETSIn accordance with regulatory accounting criteria set forth in GASB Codification (GASB Statement No. 62), enterprisefunds that are used to account for rate-regulated activities are permitted to defer certain expenses and revenues thatwould otherwise be recognized when incurred, provided that the Electric Utility is recovering or expects to recover orrefund such amounts in rates charged to its customers. Accordingly, regulatory assets relating to debt issuance costs havebeen recognized in the Statements of Net Position.NET POSITIONThe Electric Utility’s net position represents the difference between assets and deferred outflows of resources lessliabilities and deferred inflows of resources, which is classified into the following three components: – this component consists of capital assets (net of accumulated depreciation) reducedby the outstanding balances of any bonds or other borrowings that are attributable to the acquisition, construction, orimprovement of those assets, excluding unspent bond proceeds. – this component represents restricted assets less liabilities and deferred inflows related to those assets.Restricted assets are recorded when there are limitations imposed by creditors (such as through debt covenants),contributors, or laws or regulation of other governments or constraints imposed by law through constitutional provisions orthrough enabling legislation. – this component consists of net position that does not meet the definition of “restricted” or “net investment incapital assets.”CONTRIBUTIONS TO THE CITY’S GENERAL FUNDPursuant to the City of Riverside Charter, the Electric Utility may transfer up to 11.5 percent of its prior year’s grossoperating revenues, including adjustments, to the City’s general fund. In fiscal years ended June 30, 2024 and 2023,$45,289 and $42,326, respectively, was transferred, representing 11.5 percent. Additional information can be found inNote 12 of the accompanying financial statements.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTSLeases are defined by the general government as the right to use an underlying asset. As lessee, the Electric Utilityrecognizes a lease liability and a lease asset at the beginning of a lease period unless the lease is considered a short-termlease or transfers ownership of the underlying asset. Lease assets are measured based on the net present value of thefuture lease payments at inception, using the weighted average cost of capital, which approximate the incrementalborrowing rate. Re-measurement of a lease liability occurs when there is a change in the lease term and/or other changesthat are likely to have a significant impact on the lease liability. The Electric Utility calculates the amortization of thediscount on the lease liability and report that amount as outflows of resources. Payments are allocated first to accruedinterest liability and then to the lease liability. Variable lease payments based on the usage of the underlying assets are notincluded in the lease liability calculations but are recognized as outflows of resources in the period in which the obligationwas incurred. As lessor, the Electric Utility recognizes a lease receivable. The lease receivable is measured using the netpresent value of future lease payments to be received for the lease term and deferred inflow of receivables at thebeginning of the lease term. Periodic amortization of the discount on the receivable are reported as interest revenue forthat period. Deferred inflows of resources are recognized as inflows on a straight-line basis over the term of the lease. Thisrecognition does not apply to short-term leases, contracts that transfer ownership, leases of assets that are investments,or certain regulated leases. Any initial direct costs are reported as an outflow of resources for that period. Re-measurement of lease receivables occur when there are modifications, including but not limited to changes in the contractprice, lease term, and adding or removing an underlying asset to the lease agreements. In the case of a partial or full leasetermination, the carrying value of the lease receivable and the related deferred inflow of resources will be reduced and willinclude a gain or loss for the difference. For lease contracts that are short-term, the Electric Utility recognizes short-termlease payments as inflows of resources (revenues) based on the payment provisions of the lease contract. Liabilities areonly recognized if payments are received in advance, and receivables are only recognized if payments are receivedsubsequent to the reporting period. Additional disclosures regarding regulated leases are in Note 14.Subscription-Based Information Technology Arrangements (SBITAs) are contracts that convey control of the right to useanother party’s IT software, alone or in combination with tangible capital assets, as specified in the contract for a period oftime in an exchange or exchange-like transaction. To determine whether a contract conveys control of the right to use the42NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)underlying IT assets, the City assesses both the right to obtain the present service capacity from use of the underlying ITassets and the right to determine the nature and manner of use of the underlying IT assets as specified in the contract.Contracts that solely provide IT support services are excluded from the definition of a SBITA. The subscription term is theperiod during which the City has a noncancellable right to use the underlying IT assets, plus the periods covered by theCity’s option to extend the SBITA if it is reasonably certain, based on all relevant factors, that the government will exercisethat option. Periods for which both the government and the SBITA vendor have an option to terminate the SBITA withoutpermission from the other party (or if both parties have to agree to extend) are cancellable periods and are excluded fromthe subscription term. Additional disclosures regarding SBITAs are in Note 14.BUDGET AND BUDGETARY ACCOUNTINGThe Electric Utility presents, and the City Council adopts, a biennial budget. The proposed budget includes estimatedexpenses and forecasted revenues. The City Council generally adopts the Electric Utility’s budget in June biennially viaresolution.RECLASSIFICATIONSCertain reclassifications have been made to prior year’s financial statements to conform with the current year’spresentation. Such reclassifications have no effect on the net position or the changes in net position. 43NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC43
ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTSCash and investments at June 30, 2024 and 2023, consist of the following (in thousands):June 30, 2024June 30, 2023Fair ValueEquity interest in City Treasurer's investment pool$348,474$321,777Cash and investments at fiscal agent176,27358,135Total cash and investments$524,747$379,912The amounts above are reflected in the accompanying financial statements as:June 30, 2024June 30, 2023Unrestricted cash and cash equivalents$258,200$247,831Restricted cash and cash equivalents58,24144,794Restricted Public Benefits - cash and cash equivalents32,03329,152Restricted cash and investments at fiscal agent176,27358,135Total cash and investments$524,747$379,912The investment types in the tables below related to the Electric Utility’s investments in the City Treasurer’s investment poolrepresent the Electric Utility’s prorated share of the investment types in the investment pool and do not representownership interests in the individual investments. 44NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTS (CONTINUED)The Electric Utility categorizes its fair value measurements within the fair value hierarchy established by generallyaccepted accounting principles. The Electric Utility has the following recurring fair value measurements as of June 30,2024 and 2023:Investment TypeJune 30, 2024Fair ValueQuoted Prices inActive Markets forIdentical Assets(Level 1)Significant OtherObservable Inputs(Level 2)SignificantUnobservableInputs(Level 3)Investmentsnot Subject toFair ValueHierarchyHeld by fiscal agentMoney market funds$131,623$-$-$-$131,623Asset-backed securities1,988-1,988--US Treasury notes/bonds24,657-24,657--Federal agency obligations3,439-3,439--Corp medium term notes10,715-10,715--Supranational securities3,851-3,851--City Treasurer's investment pool1Money market funds333---333Joint powers authority pools 71,024---71,024Mortgage pass-through securities 10,453-10,453--Asset-backed securities30,250-30,250--US Treasury obligations 113,513-113,513--Federal agency obligations 32,221-32,221--Medium-term corporate notes 69,588-69,588--Supranational securities21,092-21,092--Total $524,747$-$321,767$-$202,980Investment TypeJune 30, 2023Fair ValueQuoted Prices inActive Markets forIdentical Assets(Level 1)Significant OtherObservable Inputs(Level 2)SignificantUnobservableInputs(Level 3)Investmentsnot Subject toFair ValueHierarchyHeld by fiscal agentMoney market funds$1,263$-$-$-$1,263Asset-backed securities3,853-3,853--Investment contracts10,761---10,761US Treasury notes/bonds24,065-24,065--Federal agency obligations3,407-3,407--Corp medium term notes11,264-11,264--Supranational securities3,522-3,522--City Treasurer's investment pool1Money market funds5,825---5,825Joint powers authority pools 62,073---62,073Mortgage pass-through securities10,596-10,596--Asset backed securities 26,896-26,896--US Treasury obligations93,152-93,152--Federal agency obligations44,548-44,548--Medium-term corporate notes 67,044-67,044--Supranational securities11,643-11,643--Total $379,912$-$299,990$-$79,9221Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financialstatements in the City’s Annual Comprehensive Financial Report.45NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC45 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTS (CONTINUED)Cash and investments distribution by maturities as of June 30, 2024 and 2023 are as follows:Remaining Maturity (in Months)Investment TypeJune 30, 2024Fair Value12 Monthsor Less13 to 36Months37 to 60MonthsMore than60 MonthsHeld by fiscal agentMoney market funds$131,623$131,623$-$-$-Asset-backed securities1,988-1,344644-US Treasury notes/bonds24,6571,48512,60910,563-Federal agency obligations3,4392,1961,243--Corp medium term notes10,7153,4153,5883,712-Supranational securities3,8519881,916947-City Treasurer's investment pool1Money market funds333333---Joint powers authority pools 71,02471,024---Mortgage pass-through securities 10,4533,1911,4965,766-Asset-backed securities30,2501,69710,33318,220-US Treasury obligations 113,513-35,61577,898-Federal agency obligations32,2219,91713,4678,837-Medium-term corporate notes 69,58810,62230,66128,305-Supranational securities21,0921,3797,65512,058-Total$524,747$237,870$119,927$166,950$-Remaining Maturity (in Months)Investment TypeJune 30, 2023Fair Value12 Monthsor Less13 to 36Months37 to 60MonthsMore than60 MonthsHeld by fiscal agentMoney market funds$1,263$1,263$-$-$-Asset-backed securities3,853-2,0651,788-Investment contracts10,761---10,761US Treasury notes/bonds 24,0655,35612,0686,641-Federal agency obligations3,407-3,407--Corp medium term notes11,2641,3118,8991,054-Supranational securities3,522-3,522--City Treasurer's investment pool1Money market funds5,8255,825---Joint powers authority pools 62,07362,073---Mortgage pass-through securities10,5961,6683,8475,081-Asset backed securities 26,89629811,99814,600-US Treasury obligations93,15215,33027,51750,305-Federal agency obligations44,54810,57227,0626,914-Medium-term corporate notes 67,0443,34736,48227,215-Supranational securities 11,643-11,643--Total$379,912$107,043$148,510$113,598$10,7611 Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financialstatements in the City’s Annual Comprehensive Financial Report.46NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTS (CONTINUED)Presented below is the actual rating as of June 30, 2024 and 2023 for each investment type:Ratings as of Year EndInvestment TypeJune 30, 2024Fair ValueAAAAAAUnratedHeld by fiscal agentMoney market funds$131,623$359$-$-$131,264Asset-backed securities1,988949--1,039US Treasury notes/bonds24,657-24,657--Federal agency obligations3,439-3,439--Corp medium term notes10,715-2,5025,7262,487Supranational securities3,851---3,851City Treasurer's investment pool1Money market funds333333---Joint powers authority pools 71,02471,024---Mortgage pass-through securities 10,4539,483970--Asset-backed securities30,25023,188--7,062US Treasury obligations113,513-113,513--Federal agency obligations 32,221-32,221--Medium-term corporate notes 69,5882,10721,43534,15111,895Supranational securities21,092---21,092Total$524,747$107,443$198,737$39,877$178,690Ratings as of Year EndInvestment TypeJune 30, 2023Fair ValueAAAAAAUnratedHeld by fiscal agentMoney market funds$1,263$999$-$-$264Asset-backed securities3,8532,815--1,038Investment contracts10,761---10,761US Treasury notes/bonds 24,06523,082-983-Federal agency obligations3,4071,376--2,031Corp medium term notes11,264-2,7546,6121,898Supranational securities3,5221,850--1,672City Treasurer's investment pool1Money market funds 5,8255,825---Joint powers authority pools 62,073---62,073Morgage pass-through securities10,59610,596---Asset backed securities 26,89620,340--6,556US Treasury obligations93,15293,152---Federal agency obligations44,54837,720--6,828Medium-term corporate notes 67,0442,12023,20032,7338,991Supranational securities11,6435,995--5,648Total$379,912$205,870$25,954$40,328$107,7601 Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financialstatements in the City’s Annual Comprehensive Financial Report.47NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC47 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 3.CAPITAL ASSETSThe following is a summary of changes in utility plant and lease and subscription assets during the fiscal years ended June30, 2024 and 2023:BalanceAs of6/30/2022AdditionsRetirements/TransfersBalanceAs of6/30/2023AdditionsRetirements/TransfersBalanceAs of6/30/2024Production$269,814$119$(3,967)$265,966$-$-$265,966Transmission50,4172,999-53,416174-53,590Distribution725,15921,894(5,176)741,87713,294(2,576)752,595General123,4323,487(4,792)122,1273,119(546)124,700Intangibles25,963704-26,667610-27,277Depreciable utility plant1,194,78529,203(13,935)1,210,05317,197(3,122)1,224,128Less accumulated depreciation:Production(120,918)(9,032)397(129,553)(8,919)-(138,472)Transmission(22,373)(1,004)-(23,377)(1,057)-(24,434)Distribution(317,978)(20,043)4,247(333,774)(20,353)1,987(352,140)General(58,400)(5,272)4,575(59,097)(4,846)546(63,397)Intangibles(15,797)(2,838)-(18,635)(2,906)-(21,541)Accumulated depreciation(535,466)(38,189)9,219(564,436)(38,081)2,533(599,984)Net depreciable utility plant659,319(8,986)(4,716)645,617(20,884)(589)624,144Land53,0423,344-56,38651(2)56,435Intangible, non-amortizable10,651--10,651--10,651Construction in progress72,72427,125(27,587)72,26227,366(14,395)85,233Nondepreciable utility plant136,41730,469(27,587)139,29927,417(14,397)152,319Total utility plant$795,736$21,483$(32,303)$784,916$6,533$(14,986)$776,463Lease and subscription assets, being amortized:1Building - intangible$348$-$-$348$-$-$348Machinery and equipment - intangible280--280123(138)265Subscription-based information technologyarrangements-128(35)93138-231Total lease and subscription assets628128(35)721261(138)844Less lease accumulated amortization:Machinery and equipment - intangible(62)(62)-(124)(61)(82)(103)Building - intangible(75)(74)-(149)(74)-(223)Subscription-based information technologyarrangements-(78)35(43)(65)-(108)Total lease accumulated amortization(137)(214)35(316)(200)82(434)Total lease and subscription assets, net$491$(86)$-$405$61$(56)$410Total capital assets being depreciated,net$796,227$21,397$(32,303)$785,321$6,594$(15,042)$776,8731 GASB 87 Leases was implemented effective July 1, 2021. GASB 96 Subscription-Based Information Technology Arrangements (SBITA) wasimplemented effective July 1, 2022. For additional information, refer to Notes 1 and 13.48NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONSThe following is a summary of changes in long-term obligations during the fiscal years ended June 30, 2024 and 2023 (inthousands):BalanceAs of6/30/2022AdditionsReductionsBalanceAs of6/30/2023AdditionsReductionsBalanceAs of6/30/2024Due WithinOne YearRevenue bonds$569,185$-$(19,358)$549,827$283,940$(156,272)$677,495$18,005Pension obligation bonds67,641-(4,233)63,408-(5,117)58,2915,675Direct borrowings:Financed purchases364-(364)-----Total long-term obligations$637,190$-$(23,955)$613,235$283,940$(161,389)$735,786$23,680Long-term debt consists of the following (in thousands):Pension Obligation Bonds PayableJune 30, 2024June 30, 2023$31,960 2017 Taxable Pension Obligation Bonds Series A: fixed rate bonds issuedby the City due in annual installments from $2,910 to $3,580 through June 2027, withcoupons from 1.3 to 3.1 percent. The Electric Utility's proportional share of theoutstanding debt is 29.4 percent.$3,091$4,065$201,080 2020 Taxable Pension Obligation Bonds Series A (Miscellaneous):fixed rate bonds issued by the City due in annual installments from $1,285 to $14,625through June 2045, with coupons from 1.7 to 3.9 percent. The Electric Utility'sproportional share of the outstanding debt is 32.9 percent.55,20059,343Total pension obligation bonds payable58,29163,408 49NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC49
ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)Revenue Bonds PayableJune 30, 2024June 30, 2023$141,840 2008 Electric Refunding/Revenue Bonds:A - $84,515 2008 Series A Bonds - variable rate bonds due in annual principalinstallments from $4,575 to $7,835 through October 1, 2029. Interest rate issubject to weekly repricing (net interest rate, including swaps, at June 30, 2023was 3.0 percent). Partially refunded $13,975 on July 25, 2013 with the 2013Electric Revenue Refunding Bonds. Partially refunded $31,500 on April 1, 2019with the 2019A Electric Refunding Bonds. Remaining par amount of $34,465was refunded with the 2024A issuance.$-$34,465C - $57,325 2008 Series C Bonds - variable rate bonds due in annual principalinstallments from $700 to $5,200 through October 1, 2035. Interest rate issubject to weekly repricing (net interest rate, including swaps, at June 30, 2023was 3.1 percent). Partially refunded $11,775 on July 25, 2013 with the 2013Electric Revenue Refunding Bonds. Partially refunded $8,925 on April 1, 2019with the 2019A Electric Refunding Bonds. Remaining par amount of $32,150was refunded with the 2024A issuance.-32,150$133,290 2010 Electric Revenue Series A Bonds: fixed rate, federally taxableBuild America Bonds due in annual principal installments from $2,300 to $33,725through October 1, 2040, interest from 6.0 to 7.6 percent, excluding 33%sequestration credit from the IRS, effective October 1, 2020.123,515126,110$56,450 2011 Electric Revenue/Refunding Series A Bonds: fixed rate bonds duein annual principal installments from $725 to $5,175 through October 1, 2035,interest of 3.2 percent. Remaining par amount of $32,875 was refunded with the2024A issuance.-33,600$79,080 2013 Electric Revenue Refunding Series A Bonds: fixed rate bonds duein annual principal installments from $795 to $2,625 through October 1, 2043,interest from 3.0 to 5.25 percent. Remaining par amount of $34,370 was refundedwith the 2023A issuance.-35,385$283,325 2019 Electric Revenue Refunding Series A Bonds: fixed rate bondsdue in annual principal installments from $3,545 to $24,005 through October 1,2048, interest of 5.0 percent232,480245,660$31,290 2023 Electric Revenue Refunding Series A Bonds: fixed rate bonds duein annual principal installments from $990 to $2,395 through October 1, 2043,interest of 5.0 percent.31,390-$213,295 2024 Electric Revenue Refunding Series A Bonds: fixed rate bondsdue in annual principal installments from $460 to $12,845 through October 1, 2049,interest of 5.0 percent.213,295-Total electric revenue bonds payable600,680507,370Total electric revenue and pension obligation bonds payable658,971570,778Unamortized bond premium76,81542,457Total electric revenue and pension obligation bonds payable, including bondpremium735,786613,235Less current portion of revenue and pension obligation bonds payable(23,680)(22,633)Total long-term electric revenue and pension obligation bonds payable$712,106$590,602NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED) - The Electric Utility is obligated to pay its share of the City’s pension obligation bonds, whichthe City issued in 2005 and refinanced a portion in May 2017.In fiscal year ended June 30, 2020, the City issued $432,165 2020 Taxable Pension Obligation Bonds Series A. The bondswere issued to reduce the City’s unfunded pension liability in both the City’s Miscellaneous and Safety CalPERS plans. It isestimated the issuance will save the City’s General Fund approximately $178.5 million throughout the life of the bonds.The fixed rate bonds issued by the City under the miscellaneous plan are due in annual installments from $1,285 to$14,625 through June 2043, with coupons from 1.7% to 3.9%. The Electric Utility's proportional share of the miscellaneousplan is 32.9%.The Electric Utility’s proportional share of the outstanding principal amount of the bonds was $58,291 and $63,408 as ofJune 30, 2024 and 2023, respectively. The bond proceeds were deposited with CalPERS to fund the unfunded actuarialaccrued liability for non-safety employees. For more discussion relating to the City’s pension obligation bond issuance, seethe notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report for the fiscal year endedJune 30, 2024. Remaining pension obligation bond debt service payments will be made from revenues of the Electric Fund. As of June 30, 2024, the annual debt service requirements to maturity are as follows (in thousands):Fiscal YearPrincipalInterestTotal2025$5,675$1,930$7,60520265,8391,7977,63620275,5961,6467,24220283,8001,4935,29320293,0271,3884,4152030-203413,8985,63219,5302035-203914,8872,72217,6092040-20435,5694105,979Total$58,291$17,018$75,309As of June 30, 2023, the annual debt service requirements to maturity were as follows (in thousands):Fiscal YearPrincipalInterestTotal2024$5,118$2,044$7,16220255,6751,9307,60520265,8391,7977,63620275,5961,6467,24220283,8001,4935,2932029-203313,7666,10919,8752034-203815,5073,32018,8272039-20438,1077238,830Total$63,408$19,062$82,470- All electric revenue bonds are covenanted per the Amended and Restated Resolution No. 17662(Electric) Master Resolution that upon the occurrence and continuation of an event of default, the owners of 25% inaggregate amount of Bond Obligation may, by written notice to the City, declare the entire unpaid principal and accretedvalue of the bonds due and payable should the City fail to pay its debts as they become due or upon the entry of anydecree or order of bankruptcy of the City.$31,390 Electric Revenue Refunding Bonds Series A. The bonds were issued in December 2023 to refund all of theoutstanding 2013A Electric Revenue Bonds. Interest on the bonds is 5%, payable April and October of each year. Principalpayments are due in annual installments through October 1, 2043, and range from $990 to $2,395.$213,295 Electric Revenue Bonds Series A. The bonds were issued in February 2024 to fund short-term and long-termcapital projects, to refund the outstanding Electric Bonds Series 2008A, 2008C, and 2011A, and pay termination costsassociated with certain interest rate swap agreements. Interest on the bonds is 5%, payable in April and October of each51year. Principal payments are due in annual installments through October 1, 2049, and range from $460 to $12,845.NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC51 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)Remaining revenue bond debt service payments will be made from revenues of the Electric Fund. As of June 30, 2024, the annual debt service requirements to maturity are as follows (in thousands):Fiscal YearPrincipalInterestTotal2025$18,005$31,946$49,951202618,47528,76347,238202719,36027,82247,182202820,32026,83047,150202921,33025,78947,1192030-2034129,835110,797240,6322035-2039158,06574,832232,8972040-2044129,24533,611162,8562045-205086,04512,83798,882Premium76,815-76,815Total$677,495$373,227$1,050,722As of June 30, 2023, the annual debt service requirements to maturity were as follows (in thousands):Fiscal YearPrincipalInterestTotal2024$17,515$23,362$40,877202518,33522,48840,823202619,30521,58040,885202720,08520,74240,827202820,96019,86440,8242029-2033118,90084,562203,4622034-2038138,57055,605194,1752039-2043121,77019,283141,0532044-204826,4304,53230,9622049-20535,5001385,638Premium42,457-42,457Total$549,827$272,156$821,983 - The Electric Utility has a number of debt issuances (revenue bonds) outstanding that arecollateralized by the pledging of electric revenues. The amount and term of the remainder of these commitments areindicated in the revenue bonds payable and annual debt service requirements to maturity tables presented within this Note4. The purpose of the debt issuances was for the financing of various Electric Utility capital improvement projects. For June 30, 2024 and 2023, debt service payments as a percentage of the pledged gross revenue, net of certainexpenses where so required by the debt agreement, are indicated in the table below. The debt service coverage ratiosalso approximate the relationship of the debt service to pledged revenue for the remainder of the term of the commitment.Fiscal Year EndedDescription ofPledged RevenuesAnnual Amount ofPledged Revenue(net of expenses) 1,2, 3Annual Debt ServicePaymentsDebt ServiceCoverageRatioJune 30, 2024Electric revenues$116,861$50,6942.31June 30, 2023Electric revenues$93,040$46,4002.011Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of $7,707 and $(1,308) for June 30, 2024 and 2023,respectively.2Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $474 and $431for June 30, 2024 and 2023, respectively.3Includes GASB 87 Leases net revenue adjustment of $304 and $247 for June 30, 2024 and 2023, respectively.NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)LINE OF CREDITOn February 1, 2019, the City entered into a subordinate line of credit agreement with U.S. Bank, National Association.The agreement was renewed on February 1, 2022. The Subordinate Line of Credit is a tool approved through the Electricand Water Utility Five-Year Rate Plan to manage rate increases by enabling the Electric Utility to reduce cash levels whilemaintaining compliance with the Riverside Public Utilities Cash Reserve Policy. Under the terms and conditions of theagreement, the City may borrow up to $35,000 for purposes of the capital or operating financial needs of the ElectricSystem. There were no borrowings against the line as of June 30, 2024 and 2023.LETTERS OF CREDITAs of June 30, 2024, the Electric Utility’s 2008 Electric Revenue Bonds (Series A and C) and 2011 Electric RevenueBonds (Series A) were fully refunded in February 2024 with the 2024A Electric Revenue Bonds, which are fixed rate bondsand no longer require letters of credit.As of June 30, 2023, the Electric Utility’s 2008 Electric Revenue Bonds (Series A and C) and 2011 Electric RevenueBonds (Series A) required an additional layer of security between the Electric Utility and the purchaser of the bonds. TheElectric Utility entered into the following three letters of credit (LOC) to provide liquidity should all or a portion of the debt beoptionally tendered to the remarketer without being successfully remarketed:

To the extent that remarketing proceeds were insufficient or not available, tendered amounts would have been paidfrom drawings made under an irrevocable direct-pay letter of credit.Liquidity advances drawn against the LOCs that were not repaid would have been converted to an installment loan withthe principal to be paid quarterly not to exceed a 5-year period for the 2008A and 2008C bonds not to exceed a 3-yearperiod for the 2011A bonds. The various indentures allowed the Electric Utility to convert the mode of the debt in thecase of a failed remarketing. For the 2008A and 2008C Bonds, the Electric Utility would have been required to pay annual interest equal to the BaseRate plus 2%, where the Base Rate was the highest of 8%, the Prime Rate plus 2.5%, the Federal Funds Rate plus2.5% and 1.50% of the yield on the 30-year U.S. Treasury Bond.For the 2011A Bonds, the Electric Utility would have been required to pay annual interest equal to the Base Rate plus2%, where the Base Rate is the highest of 10.5%, the Prime Rate plus 1% and the Federal Funds Rate plus 2%.No amounts had ever been drawn against the three LOCs due to a failed remarketing.INTEREST RATE SWAPS ON REVENUE BONDSAs of February 1, 2024, the Electric Utility no longer has any cash flow hedging derivative instruments, which are pay-fixedswaps. The 2008 Electric Refunding/Revenue Bonds (Series A and C) and the 2011 Electric Revenue Bonds (Series A)were fully refunded in February with the 2024A Electric Revenue Bonds. These swaps were employed as a hedge againstdebt that was refunded in 2008 and 2011. At the time of the refunding, hedge accounting ceased to be applied. Thebalance of the deferral account for each swap was included as part of the deferred loss on refunding associated with thenew bonds. The swaps were also employed as a hedge against the new debt. Hedge accounting was applied to thatportion of the hedging relationship, which was determined to be effective. The negative fair value of the interest rate swapsrelated to the new hedging relationship was recorded and deferred on the Statements of Net Position.53NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC53 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)As of June 30, 2023, the Electric Utility had three cash flow hedging derivative instruments, which were pay-fixed swaps.These swaps were employed as a hedge against debt that was refunded in 2008 and 2011. At the time of the refunding,hedge accounting ceased to be applied. The balance of the deferral account for each swap was included as part of thedeferred loss on refunding associated with the new bonds. The swaps were also employed as a hedge against the newdebt. Hedge accounting was applied to that portion of the hedging relationship, which was determined to be effective. A summary of the derivative activity for the year ended June 30, 2023 was as follows:OutstandingNotionalAmountFair Valueas ofJune 30, 2023Change inFair Valuefor Fiscal Year2008 Electric Refunding/Revenue Bonds Series A$34,465$(491)$1,3942008 Electric Refunding/Revenue Bonds Series C$32,150$(1,809)$1,6862011 Electric Refunding/Revenue Bonds Series A$33,600$(1,797)$1,728Objective: In order to lower borrowing costs as compared to fixed-rate bonds, the Electric Utility entered into interest rateswap agreements in connection with its $141,840 2008 Electric Refunding/Revenue Bonds (Series A and C) and $56,4502011 (Series A).Terms: Per the swap agreements, the Electric Utility payed the counterparty a fixed payment and received a variablepayment computed as 62.68% of the London Interbank Offering Rate (“LIBOR”) one month index plus 12 basis points.The swaps had notional amounts equal to the principal amounts stated above. The Electric Refunding/Revenue 2008 (Series A) Bonds' and the related swap agreements' term to maturity was October1, 2029 and the 2008 (Series C) and 2011 (Series A) Bonds' term to maturity was October 1, 2035. Replacement of LIBOR: As of July 1, 2023, LIBOR was no longer an appropriate benchmark interest rate for a derivativeinstrument that hedges the interest risk for taxable debt for purposes of GASB Statement 53.As of June 30, 2023 rates were as follows:2008 ElectricRefunding/RevenueSeries A Bonds2008 ElectricRefunding/RevenueSeries C Bonds2011 ElectricRefunding/RevenueSeries A BondsInterest rate swap:TermsRatesRatesRatesFixed payment to counterpartyFixed%3.11100%3.20400%3.20100Variable payment from counterparty62.68 LIBOR +%(0.69885)%(0.69911)%(0.75953)Net interest rate swap payments12 bps%2.41215%2.50489%2.44147Variable-rate bond coupon payments %0.56351%0.57077%0.68005Synthetic interest rate on bonds%2.97566%3.07660%3.12152Fair value: As of June 30, 2023, in connection with all swap agreements, the transactions had a total negative fair value of$(4,097). Because the coupons on the Electric Utility’s variable-rate bonds adjusted to changing interest rates, the bondsdid not have a corresponding fair value decrease. The fair value was developed by a pricing service using the zero-couponmethod, which calculated the future net settlement payments required by the swaps, assuming that the current forwardrates implied by the yield curve correctly anticipated future spot interest rates. These payments were then discountedusing the spot rates implied by the current yield curve for hypothetical zero-coupon bonds due on the date of each futurenet settlement of the swap.Credit risk: As of June 30, 2023, the Electric Utility was not exposed to credit risk because the swaps had a negative fairvalue. The swaps counterparties, J.P. Morgan Chase & Co. and Bank of America Corp., were rated A- and BBB+,respectively by Standard & Poor’s (S&P). To mitigate the potential for credit risk, the swap agreements required the fairvalue of the swaps to be collateralized by the counterparty with U.S. Government securities if the counterparties’ ratingdecreased to negotiated trigger points. Collateral would have been posted with a third-party custodian. At June 30, 2023,there was no requirement for collateral posting for any of the outstanding swaps.54NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)Basis risk: As noted above, the swaps exposed the Electric Utility to basis risk should the relationship between LIBORand the variable interest rates converge, changing the synthetic rate on the bonds. If a change occured that resulted in therates moving to convergence, the expected cost savings would have been realized.Termination risk: The derivative contract used the International Swap Dealers Association Master Agreement, whichincluded standard termination events, such as failure to pay and bankruptcy. The Schedule to the Master Agreementincluded an “additional termination event.” That was, a swap could have been terminated by the Electric Utility if eithercounterparty’s credit quality fell below “BBB-” as issued by S&P. The Electric Utility or the counterparty could terminate aswap if the other party failed to perform under the terms of the contract. If a swap was terminated, the variable-rate bondwould have no longer carried a synthetic interest rate. Also, if at the time of termination, a swap had a negative fair value,the Electric Utility would have been liable to the counterparty for a payment equal to the swap’s fair value.Swap payments and associated debt: As of June 30, 2023, the debt service requirements of the variable-rate debt andnet swap payments, assuming current interest rates remained the same for their term, were summarized in the tablebelow. Variable-Rate BondsFiscal YearEndingJune 30,PrincipalInterestInterest RateSwaps, NetTotal2024$725$671$2,703$4,09920257256652,6814,07120261,4506292,5324,61120277,4255822,33110,33820287,8855312,12110,5372029-203351,9801,7957,05960,8342034-203830,0252741,07531,374Total$100,215$5,147$20,502$125,864FINANCED PURCHASESThe Electric Utility has entered into sixteen purchase agreements for financing sixteen compressed natural gas heavy dutyservice trucks. All agreements have seven-year terms of monthly payments with interest rates ranging from 2% to 2.5%.The total gross value of all existing agreements is $5,715 with depreciation over the seven-year terms using the straight-line method. As of June 30, 2023, the total liability was $0. The final payment on this agreement was made in February 2023, whichconsisted of $364 principal and $2 interest. No further payments were due. 5.COMPENSATED ABSENCESA liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement tothese balances are attributable to services already rendered and it is probable that virtually all of these balances will beliquidated by either paid time-off or payments upon termination or retirement.Below is a summary of changes in Compensated absences for the Electric Utility as of June 30, 2024 and 2023:BalanceAs of6/30/2022AdditionsReductionsBalanceAs of6/30/2023AdditionsReductionsBalanceAs of6/30/2024Due Within OneYearCompensated absences$7,200$5,659$(5,381)$7,478$5,313$(5,391)$7,400$5,33555NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC55 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLANPLAN DESCRIPTIONThe Electric Utility's employees participate in the City’s Miscellaneous (non-safety) Plan (the Plan), an agent multipleemployer public employee defined benefit pension plan. CalPERS provides retirement and disability benefits, annual cost-of-living adjustments, and death benefits to plan members and beneficiaries. CalPERS acts as a common investment andadministrative agent for participating public entities within the State of California. CalPERS issues a publicly availablefinancial report that includes financial statements and required supplementary information for the cost sharing plans thatare administered by CalPERS. Benefit provisions and all other requirements are established by state statute and Cityordinance. A copy of CalPERS’ annual financial report may be obtained online at www.calpers.ca.gov. FUNDING POLICYThe City has contributed at the actuarially determined rate provided by CalPERS’ actuaries. Participants are required tocontribute 8% of their annual covered salary. The City has a multiple tier retirement plan with benefits varying by plan. Allpermanent full-time and selected part-time employees are eligible for participation in CalPERS. Benefits vest after fiveyears of service and are determined by a formula that considers the employee’s age, years of service and salary. Underthe Plan, the City pays the employees’ contribution to CalPERS for employees hired on or before specific dates as follows:1stTier –The retirement formula is 2.7% at age 55 for employees hired on or before October 18, 2011. Effective January1, 2018 for unrepresented employees (Sr. Management, Management, Professional, Para-professional,Supervisory, Confidential, and Executive units, excluding the Chief of Police and the Fire Chief), the employeeswere required to pay 2% of their pensionable income, with the City contributing the other 6%. Effective January1, 2019, employees were required to pay an additional portion of their pensionable income. This portion was athree-year increase of 2% (2019), 2% (2020) and 2% (2021). As of 2021, employees are contributing the entire8% of their pensionable income.The retirement formula is 2.7% at age 55 for SEIU and SEIU Refuse employees hired before June 7, 2011.Currently, employees are required to pay 7% of their pensionable income with the City contributing the other1%. Effective January 1, 2019, employees were required to pay an additional portion of their pensionableincome. This portion was a two-year increase of 1% (2019) and 1% (2020). As of 2020, employees arecontributing the entire 8% of their pensionable income.The retirement formula is 2.7% at age 55 for IBEW and IBEW Supervisory employees hired on or beforeOctober 18, 2011. Effective November 1, 2017, employees were required to pay 2% of their total pensionableincome with the City paying the remaining 6%. Effective each November 1st, employees were required to payan additional portion of their pensionable income. This portion was a three-year increase of 2% (2018), 2%(2019) and 2% (2020). As of November 2020, employees are contributing the entire 8% of their pensionableincome.2ndTier –The retirement formula is 2.7% at age 55, and:Miscellaneous employees, IBEW, and IBEW Supervisory hired on or after October 19, 2011 pay their share(8%) of contributions.SEIU and SEIU Refuse employees hired on or after June 7, 2011 pay their share (8%) of contributions.3rdTier – The retirement formula is 2% at age 62 for new members hired on or after January 1, 2013 and theemployee must pay the normal cost to CalPERS, which is currently at 8.25%. Classic members (CalPERSmembers prior to 12/31/12) hired on or after January 1, 2013 may be placed in a different tier.The contribution requirements of plan members and the City are established and may be amended by CalPERS.5656NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)BENEFITS PROVIDEDCalPERS provides service retirement and disability benefits, annual cost-of-living adjustments and death benefits to planmembers who must be public employees and beneficiaries. Benefits are based on years of credited service, equal to oneyear of full-time employment. Members with five years of total service are eligible to retire at age 50 with statutorily reducedbenefits. All members are eligible for non-duty disability benefits after five years of service. The death benefit is one of thefollowing: the Basic Death Benefit, the 1959 Survivor Benefit Level III, or the Optional Settlement 2W Death Benefit. Thecost-of-living adjustments for the Plan are applied as specified by the Public Employees’ Retirement Law.CONTRIBUTIONSSection 20814(c) of the California Public Employees’ Retirement Law requires that the employer contribution rates for allpublic employers be determined on an annual basis by the actuary and shall be effective on the July 1 following notice of achange in the rate. Funding contributions for the Plan is determined annually on an actuarial basis as of June 30 byCalPERS. The actuarially determined rate is the estimated amount necessary to finance the costs of benefits earned byemployees during the year, with an additional amount to finance any unfunded accrued liability. The City is required tocontribute the difference between the actuarially determined rate and the contribution rate of employees.NET PENSION LIABILITYThe City’s net pension liability for the Plan is measured as the total pension liability, less the pension plan’s fiduciary netposition. For fiscal year ended June 30, 2024, the net pension liability of the Plan is measured as of June 30, 2023, usingan annual actuarial valuation as of June 30, 2022 rolled forward to June 30, 2023 using standard update procedures. Forfiscal year ended June 30, 2023, the net pension liability of the Plan is measured as of June 30, 2022, using an annualactuarial valuation as of June 30, 2021 rolled forward to June 30, 2022 using standard update procedures. A summary ofprincipal assumptions and methods used to determine the net pension liability is shown below:ACTUARIAL ASSUMPTIONSThe total pension liabilities in the June 30, 2023 and 2022 actuarial valuations were determined using the followingactuarial assumptions:Miscellaneous - Current YearMiscellaneous - Prior YearValuation DateJune 30, 2022June 30, 2021Measurement DateJune 30, 2023June 30, 2022Actuarial Cost MethodEntry-Age Normal Cost MethodEntry-Age Normal Cost MethodActuarial AssumptionsDiscount Rate6.90% 6.90%Inflation2.30% 2.30%Salary IncreaseVaries by entry age and serviceVaries by entry age and serviceMortality Rate Table1Derived using CalPERS’ membership data for all funds.Post Retirement BenefitIncreaseThe lesser of contract COLA or 2.30% until PurchasingPower Protection Allowance floor on purchasing powerapplies, 2.30% thereafterThe lesser of contract COLA or 2.30% untilPurchasing Power Protection Allowance floor onpurchasing power applies, 2.30% thereafter1The mortality table used was developed based on CalPERS-specific data. The probabilities of mortality are based on the 2021 CalPERS ExperienceStudy for the period from 2001 to 2019. Pre-retirement and Post-retirement mortality rates include generational mortality improvement using 80% ofScale MP-2020 published by the Society of Actuaries. For more details on this table, please refer to the CalPERS Experience Study and Review ofActuarial Assumptions report from November 2021 that can be found on the CalPERS website.57NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC57 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)LONG-TERM EXPECTED RATE OF RETURNThe long-term expected rate of return on pension plan investments was determined using a building-block method inexpected future real rates of return (expected returns, net of pension plan investment expense and inflation) are developedfor each major asset class. In determining the long-term expected rate of return, CalPERS took into account both short-term and long-term market return expectations. Using historical returns of all of the funds’ asset classes, expectedcompound (geometric) returns were calculated over the next 20 years using a buildingblock approach. The expected rateof return was then adjusted to account for assumed administrative expenses of 10 Basis points. The expected real rates ofreturn by asset class are as follows: June 30, 2023 Measurement DateAsset Class(1)Assumed AssetAllocation Real Return(1),(2)Global Equity - Cap-weighted30.00%4.54%Global Equity - Non-Cap-weighted12.00% 3.84%Private Equity13.00% 7.28%Treasury5.00% 0.27%Mortgage-backed Securities5.00% 0.50%Investment Grade Corporates10.00% 1.56%High Yield5.00% 2.27%Emerging Market Debt5.00% 2.48%Private Debt5.00% 3.57%Real Assets15.00% 3.21%Leverage(5.00)% (0.59)%(1) An expected inflation of 2.30% used for this period.(2) Figures are based on the 2021 Asset Liability Management study.June 30, 2022 Measurement DateAsset Class(1)Assumed AssetAllocation Real Return(1),(2)Global Equity - Cap-weighted30.00%4.54%Global Equity - Non-Cap-weighted12.00%3.84%Private Equity13.00%7.28%Treasury5.00%0.27%Mortgage-backed Securities5.00%0.50%Investment Grade Corporates10.00%1.56%High Yield5.00%2.27%Emerging Market Debt5.00%2.48%Private Debt5.00%3.57%Real Assets15.00%3.21%Leverage(5.00)%(0.59)%(1) An expected inflation of 2.30% used for this period.(2) Figures are based on the 2021 Asset Liability Management study.DISCOUNT RATEThe discount rate used to measure the total pension liability was 6.90% and 6.90% for measurement dates as of June 30,2023 and 2022, respectively. The projection of cash flows used to determine the discount rate assumed that contributionsfrom plan members will be made at the current member contribution rates and that contributions from employers will bemade at statutorily required rates, actuarially determined. Based on those assumptions, the Plan’s fiduciary net positionwas projected to be available to make all projected future benefit payments of current plan members. Therefore, the long-term expected rate of return on plan investments was applied to all periods of projected benefit payments to determine thetotal pension liability.58NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)DISCOUNT RATE (CONTINUED) - In 2022, SB 1168 increased the standard retiree lump sum death benefit from $500 to$2,000 for any death occurring on or after July 1, 2023. The impact, if any, is included in the changes of benefit terms.CHANGES IN ASSUMPTIONSEffective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from7.15% to 6.90%. In determining the long-term expected rate of return, CalPERS took into account long-term market returnexpectations as well as the expected pension fund cash flows. Projected returns for all asset classes were estimated,combined with risk estimates, and used to project compound (geometric) returns over the long term. The discount rateused to discount liabilities was informed by the long-term projected portfolio return. In addition, demographic assumptionsand the inflation rate assumption were changed in accordance with the 2021 CalPERS Experience Study and Review ofActuarial Assumptions.There were no assumption changes in valuation dated June 30, 2022 (2023 measurement date).CHANGES IN THE NET PENSION LIABILITY (ASSET)The changes in the Electric Utility’s proportionate share of the net pension liability/(asset) as of June 30, 2024(measurement date June 30, 2023) and 2023 (measurement date June 30, 2022) for the Plan are as follows:June 30, 2024Net PensionLiability/(Asset)Proportion ofthe PlanProportion - Reporting date June 30, 2024(Measurement Date June 30, 2023)$44,227%28.53Proportion - Reporting date June 30, 2023(Measurement Date June 30, 2022)38,748%29.42Changes - Increase / (Decrease)5,479%(0.89)June 30, 2023Proportion - Reporting date June 30, 2023(Measurement Date June 30, 2022)38,748%29.42Proportion - Reporting date June 30, 2022(Measurement Date June 30, 2021)(26,219)%29.56Changes - Increase / (Decrease)64,967%(0.14)PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TOPENSIONFor the fiscal years ended June 30, 2024 and 2023, the Electric Utility recognized pension expense of $13,766 and $7,266,respectively. At June 30, 2024 and 2023, the Electric Utility reported deferred outflows/(inflows) of resources related topension from the following sources:June 30, 2024June 30, 2023DeferredOutflows ofResources DeferredInflows ofResources DeferredOutflows ofResources DeferredInflows ofResources Pension contribution subsequent to themeasurement date$6,060$-$8,574$-Changes in Assumptions2,106-3,982-Difference between expected and actualexperience2,505(1,892)263(3,577)Net difference between projected andactual earnings on pension planinvestments20,347-22,112-Total$31,018$(1,892)$34,931$(3,577)59NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC59 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TOPENSION (CONTINUED)Deferred outflows of resources related to contributions subsequent to the measurement date reported in prior year wasrecognized as a reduction of the net pension liability in the year ended June 30, 2025 and 2024, respectively.At June 30, 2024 and 2023, the Electric Utility reported deferred outflows/(inflows) of resources related to pension to berecognized as pension expense as follows:Year EndedJune 30Deferred Outflows/(Inflows) ofResources2025$5,10120263,189202714,1742028602Total$23,066Year EndedJune 30Deferred Outflows/(Inflows) ofResources2024$4,04920253,47120261,500202713,760Total$22,780On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for fiscal year 2020-21. Based on thethresholds specified in CalPERS Funding Risk Mitigation policy, the excess return of 14.3% prescribed a reduction ininvestment volatility that corresponds to a reduction in the discount rate used for funding purposes of 0.20%, from 7.00%to 6.80%. Since CalPERS was in the final stages of the four-year Asset Liability Management (ALM) cycle, the boardelected to defer any changes to the asset allocation until the ALM process concluded, and the board could make its finaldecision on the asset allocation in November 2021. On November 17, 2021, the board adopted a new strategic asset allocation. The new asset allocation along with the newcapital market assumptions, economic assumptions and administrative expense assumption supported a discount rate of6.90% (net of investment expense but without a reduction for administrative expense) for financial reporting purposes. Thisincluded a reduction in the price inflation assumption from 2.50% to 2.30% as recommended in the November 2021CalPERS Experience Study and Review of Actuarial Assumptions. This study also recommended modifications toretirement rates, termination rates, mortality rates and rates of salary increases that were adopted by the board. Thesenew assumptions were reflected in the GASB 68 accounting valuation reports for the June 30, 2022, measurement date. Events Subsequent to June 30, 2022 valuation date (2023 measurement date) - There were no subsequent events thatwould materially affect the results in this disclosure. SENSITIVITY OF THE NET PENSION LIABILITY (ASSET) TO CHANGES IN THE DISCOUNT RATEThe following presents the Electric Utility’s proportionate share of the net pension liability of the Plan, calculated using thediscount rate of 6.90% (measurement date June 30, 2023) and 6.90% (measurement date June 30, 2022), as well as whatthe Electric Utility’s proportionate share of the net pension liability would be if it was calculated using a discount rate that is1-percentage point lower or 1-percentage point higher than the current rate:60NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)SENSITIVITY OF THE NET PENSION LIABILITY (ASSET) TO CHANGES IN THE DISCOUNT RATE(CONTINUED)Measurement DateJune 30, 2023Measurement DateJune 30, 2022Discount Rate-1%(5.90%)CurrentDiscount Rate(6.90%)Discount Rate+1%(7.90%)Discount Rate-1%(5.90%)CurrentDiscount Rate(6.90%)Discount Rate+1%(7.90%)Electric Utilitiy'sproportionate share of thePlan's net pension liability$108,540$44,227$(8,639)$103,174$38,748$(14,155)Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports. 61NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC61
ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB)PLAN DESCRIPTIONEmployees of the Electric Utility participate in the City’s defined benefit OPEB plan, Retiree Health Plan, providescontinuation of medical (including prescription drugs) and dental coverage benefits to retirees and surviving spouses in theform of an implied rate subsidy. The Retiree Health Benefits plan is a single employer defined benefit OPEB planadministered by the City. No assets are accumulated in a trust that meets the criteria in paragraph 4 of GASB StatementNo. 75.BENEFITS PROVIDED Eligibility for continuation of coverage requires retirement from the City and CalPERS with at least 5 years of City service.The retiree is responsible for 100% of the premium cost for coverage, which is based on the blended experience of boththe active and retired employees. The City is not required by law or contractual agreement to provide funding other thanthe pay-as-you-go amount necessary to provide current benefits to eligible retirees and beneficiaries. Retiree and spousalcoverage terminate when the retiree becomes covered under another employer health plan, or when the retiree reachesMedicare eligibility age, which is currently age 65. However, retiree benefits continue to the surviving spouse if the retireeelects the CalPERS survivor annuity.ACTUARIAL ASSUMPTIONSThe total OPEB liability was determined by actuarial valuation as of June 30, 2023 and 2022 using the following actuarialassumptions:Miscellaneous - Current YearMiscellaneous - Prior YearValuation DateJune 30, 2023June 30, 2021Measurement DateJune 30, 2023June 30, 2022Actuarial Cost MethodPay-as-you-go for implicit rate subsidyPay-as-you-go for implicit rate subsidyActuarial AssumptionsDiscount RateBond Buyer 20 Index at June 30, 2023resulting in a rate of 3.65%Bond Buyer 20 Index at June 30, 2022resulting in a rate of 3.54%Inflation Rate2.50% per annum 2.50% per annumPayroll Increases2.75% per year. Since benefits do not dependon salary (as they do for pensions), thisassumption is only used to determine theaccrual pattern of the Actuarial Present Valueof Projected Benefit Payments.2.75% per year. Since benefits do notdepend on salary (as they do for pensions),this assumption is only used to determinethe accrual pattern of the Actuarial PresentValue of Projected Benefit Payments.Merit Increasesn/an/aMortality2021 CalPERS Retiree Mortality Table for theappropriated population2017 CalPERS Retiree Mortality Table forthe appropriated populationHealthcare TrendMedical trend in future years has beenMedical trend in future years has beenRatesupdated to 4.00% for all years.updated to 4.00% for all years from 6.25%tiered down by 0.25% per year to 4.50% inall future years.62NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)CHANGES OF ASSUMPTIONSIn 2023, the discount rate was changed from 3.54% to 3.65%. In 2022, the discount rate was changed from 2.16% to3.54%. SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN HEALTHCARE COST TREND RATESThe following presents the Electric Utility’s proportionate share of the City’s total OPEB liability, calculated using thehealthcare trend rate of 4.00% for the measurement date as of June 30, 2023 and 2022, as well as what the ElectricUtility’s total OPEB liability would be if it was calculated using a healthcare cost trend rate that is 1-percentage-point loweror 1-percentage-point higher than the current rate:Measurement DateJune 30, 2023Measurement DateJune 30, 20221% DecreaseCurrenthealthcare costtrend rate 4%1% Increase1% DecreaseCurrenthealthcare costtrend rate 4%1% IncreaseElectric Utility's proportionateshare of thetotal OPEB liability$8,014$10,446$10,396$8,627$9,837$11,213SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN DISCOUNT RATESThe following presents the Electric Utility’s proportionate share of the City's total OPEB liability, calculated using thediscount rate of 3.65% and 3.54% for measurement dates of June 30, 2023 and 2022 respectively, as well as what theElectric Utility’s total OPEB liability would be if it was calculated using a discount rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:Measurement DateJune 30, 2023Measurement DateJune 30, 20221% Decrease(2.65%)Current DiscountRate(3.65%)1% Increase(4.65%)1% Decrease(2.54%)Current DiscountRate(3.54%)1% Increase(4.54%)Electric Utility'sproportionate share of thetotal OPEB liability$9,942$10,446$8,337$10,782$9,837$9,169CHANGE IN TOTAL OPEB LIABILITYFor fiscal years ended June 30, 2024 and 2023, the Electric Utility recognized total OPEB expense of $474 and $431respectively. The following table shows the change in the Electric Utility’s proportionate share of the City’s total OPEBliability for the year ended June 30, 2024 (measurement date June 30, 2023) and the year ended June 30, 2023(measurement date June 30, 2022):63NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC63 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)CHANGE IN TOTAL OPEB LIABILITY (CONTINUED)June 30, 2024Net OPEBLiabilityProportion ofthe PlanProportion - Reporting date June 30, 2024 (Measurement Date June 30, 2023)$10,446%18.68Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022)9,837%21.63Changes - Increase / (Decrease)609%-2.95June 30, 2023Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022)9,837%21.63Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021)10,460%21.45Changes - Increase / (Decrease)(623)%0.18DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEBAt June 30, 2024 and 2023, the Electric Utility reported deferred outflows/(inflows) of resources related to OPEB from thefollowing sources:Deferred Outflowsof Resources Deferred Inflows ofResources Difference between expected andactual experience$218$(564)Changes of assumptions991(1,474)Contributions subsequent tomeasurement date289-Total$1,498$(2,038)Deferred Outflowsof Resources Deferred Inflows ofResources Difference between expected andactual experience$29$(649)Changes of assumptions1,254(1,617)Contributions subsequent tomeasurement date309-Total$1,592$(2,266)At June 30, 2024 and 2023, the Electric Utility reported deferred outflows/(inflows) of resources related to OPEB to berecognized as OPEB expense as follows: 64NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB (CONTINUED)Year EndedJune 30Deferred Outflows/(Inflows) ofResources2025$(13)2026322027402028402029(194)Thereafter(734)Total$(829)Year EndedJune 30Deferred Outflows/(Inflows) ofResources2024$(27)2025(27)202615202722202822Thereafter(988)Total$(983) 8.RESTRICTED NET POSITIONThe California Code of Regulations establishes a restriction on the use of proceeds obtained from the sale of greenhousegas allowances at auctions held pursuant to California’s Cap-and-Trade Program. The proceeds are to be used exclusivelyfor the benefit of retail ratepayers of each electrical distribution utility and may not be used for the benefit of entities orpersons other than such ratepayers. In addition, the Low Carbon Fuel Standard Program (LCFS) was established andrestricts the use of the proceeds obtained from the sale of LCFS credits. The available funds are to be utilized forqualifying projects that support the Electric Utility's customers who are existing and future electric vehicle owners.Accordingly, a reserve for regulatory requirements has been established by restricting assets and reserving a portion of netposition. See Note 11 for additional information regarding the Cap-and-Trade Program and the LCFS Program.Pursuant to applicable bond indentures, a reserve for debt service has been established by restricting assets andreserving a portion of net position. Bond indentures for the Electric Utility’s electric revenue and refunding bonds requiredebt service reserves that equate to the maximum annual debt service required in future years and bond service reservesof three months interest and nine months principal due in the next fiscal year. Variable rate revenue and refunding bondsrequire 110% of the monthly accrued interest to be included in the reserve. As of June 30, 2024, the Electric revenuebonds requiring reserves (2008A & C) were fully refunded with 2024A issue. Certain issues have no debt service reserverequirements (2010A, 2019A, 2023A, and 2024A). As of June 30, 2024, the Electric revenue bonds that have no debtservice reserve requirements (2011A and 2013A) were fully refunded with 2024A and 2023A issues, respectively. SeeNote 4 for further discussion related to the Electric Utility’s debt issuances. In the Annual Valuation Report as of June 30, 2021, CalPERS reported an investment return of 21.3%. These positivereturns contributed to the reduction of the unfunded accrued liability (UAL). The City did not eliminate the budgeted UALpayments during the amendment of the fiscal year 2023-24 budget, but rather redirected those budgeted payments therespective funds' restricted cash and investments held at fiscal agent and restricted fund balance for future UAL costs.See Note 6 for further discussion related to the UAL. 65NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC65 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 9.JOINTLY-GOVERNED ORGANIZATIONSSOUTHERN CALIFORNIA PUBLIC POWER AUTHORITYOn November 1, 1980, the City joined with the Imperial Irrigation District and the cities of Los Angeles, Anaheim, Vernon,Azusa, Banning, Colton, Burbank, Glendale and Pasadena to create the Southern California Public Power Authority(SCPPA) by a Joint Powers Agreement under the laws of the State of California. As of July 2001, the City of Cerritos wasadmitted as an additional member of SCPPA. The primary purpose of SCPPA is to plan, finance, develop, acquire,construct, operate and maintain projects for the generation and transmission of electric energy for sale to its participants.SCPPA is governed by a Board of Directors, which consists of one representative from each of the members. During fiscalyears ended June 30, 2024 and 2023, the Electric Utility paid approximately $24,739 and $21,088, respectively, to SCPPAunder various take-or-pay and renewable contracts that are described in greater detail in Note 11. These payments arereflected as a component of production and purchased power and transmission expenses in the financial statements.POWER AGENCY OF CALIFORNIAOn July 1, 1990, the City joined with the cities of Azusa, Banning and Colton to create the Power Agency of California(PAC) by a Joint Powers Agreement under the laws of the State of California. The City of Anaheim joined PAC on July 1,1996. The primary purpose of PAC is to take advantage of synergies and economies of scale as a result of the five citiesacting in concert. PAC has the ability to plan, finance, develop, acquire, construct, operate and maintain projects for thegeneration and transmission of electric energy for sale to its participants. PAC is governed by a Board of Directors, whichconsists of one representative from each of the members. The term of the Joint Powers Agreement is 50 years. EffectiveJune 30, 2001, PAC was placed in an inactive status by the Board of Directors. The Agency can only be reactivated byauthorization of the Agency Board. 66NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 10.JOINTLY-OWNED UTILITY PROJECT - SONGSThe City has a 1.79 percent undivided ownership interest in Units 2 and 3 of SONGS, located south of the City of SanClemente in northern San Diego County. Both Units 2 and 3 of SONGS were permanently retired in June 2013.Consequently, the units are no longer a source of supply for the Electric Utility, but remain associated with certain of itscosts, including those associated with the units’ shutdown and decommissioning.The other owners are SCE, with a 78.21 percent interest (including the 3.16 percent interest it acquired from the City ofAnaheim in 2006), and San Diego Gas & Electric Company (SDG&E), with a 20.00 percent interest.In 2005, the California Public Utilities Commission (CPUC) authorized a project to install four new steam generators inUnits 2 and 3 at SONGS and remove and dispose of the predecessor generators. SCE completed the installation of thesesteam generators in 2010 and 2011 for Units 2 and 3, respectively. The Electric Utility’s share of the cost to replace thesteam generators was approximately $13.4 million. Replacement of the steam generators was expected to enable plantoperations to continue through at least 2022, and perhaps beyond, subject to the approval of the NRC.In January 2012, a water leak occurred in one of the heat transfer tubes of Unit 3’s steam generators, causing it to be shutdown. At that time, Unit 2 was off-line for a planned outage when unexpected wear in areas of tube-to-support structurewere found. Units 2 and 3 remained off-line for extensive inspections, testing and analysis of their steam generators. OnJune 7, 2013, SCE unilaterally announced its plan to retire Units 2 and 3 permanently. As a result of SCE’s decision to permanently retire SONGS Units 2 and 3, thedecommissioning phase of the plant began in June 2013. The process of decommissioning the nuclear power plant isexpected to take many years and is governed by NRC regulations. According to SCE’s decommissioning cost estimatedocument as of March 2018 in 2017 dollars, total decommissioning costs for Units 2 and 3 were estimated at $4.7 billion,of which the Electric Utility’s share was $84 million.In August 2021, SCE provided the updated decommissioning cost estimate document in 2020 dollars. According to theupdate, total decommissioning costs for Units 2 and 3 are estimated at $5.2 billion, of which the Electric Utility's share is$93.8 million. As of June 30, 2024, the Electric Utility has set aside $45,009 in cashinvestments with the trustee and $10,885 in a designated decommissioning reserve for the Electric Utility’s estimatedshare of the decommissioning costs. Increases to the funds held for decommissioning liability are from investmentearnings. The investment earnings are included in investment income in the Electric Utility’s financial statements. Anequivalent amount is reflected as decommissioning expense, which is considered part of production and purchased power.Decreases to the funds held for decommissioning liability are from actual funds drawn from the trust for decommissioningcosts invoiced by SCE.On February 23, 2016, the City Council adopted a resolution authorizing the commencement of SONGS decommissioningeffective June 7, 2013. This resolution allows the Electric Utility to access the decommissioning trust funds to pay for itsshare of decommissioning costs. The Electric Utility began drawing decommissioning trust funds to pay fordecommissioning costs in the fiscal year ended June 30, 2017. As of June 30, 2024, the Electric Utility has paid to date$49,537 in decommissioning obligations, which have been reimbursed by the trust funds.As of June 30, 2024 and 2023, decommissioning liability balance was $46,082 and $48,873, respectively, with a portionreflected as current liabilities payable from restricted assets. As a result of the updated SCE decommissioning costestimate and the increase in the Electric Utility's estimated share, the decommissioning liability was increased by $5.7million in fiscal year 2022. The offset of this liability increase was recorded as an extraordinary item in fiscal year 2021/22.The Electric Utility no longer provides additional funding to the trustee. However, since the decommissioning cost estimateis subject to a number of uncertainties including the cost of disposal of nuclear waste, site remediation costs, as well as anumber of other assumptions and estimates, the Electric Utility has set aside funds in the designated decommissioningreserve of $2,000 per year through fiscal year 2024, as approved by the Board of Public Utilities and City Council.Beginning in fiscal year 2025, the Electric Utility will continue to set aside funds in the designated decommissioning reserveof $1,000 per year, as approved by the Board of Public Utilities and City Council.BalanceAs of6/30/2022AdditionsReductionsBalanceAs of6/30/2023AdditionsReductionsBalanceAs of6/30/2024Due Within OneYearNuclear decommissioning liability$53,310$907$(5,344)$48,873$863$(3,654)$46,082$12,24467NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC67 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTSThe Electric Utility has a power purchase contract with Intermountain Power Agency (IPA) for the delivery of electric power.The Electric Utility’s share of IPA power is equal to 7.6 percent, or approximately 137.1 MW, of the net generation outputof IPA’s 1,800 MW central Utah coal-fueled generating station, known as Intermountain Power Project (IPP). The contractexpires in 2027.The contract constitutes an obligation of the Electric Utility to make payments solely from operating revenues. The powerpurchase contract requires the Electric Utility to pay certain minimum charges that are based on debt service requirementsand other fixed costs. Such payments are considered a cost of production.On September 29, 2006, Senate Bill (SB) 1368 was enacted into law. The bill requires electric service providers to limitfinancial investments in power plants to those that adhere to greenhouse gas performance standards as determined by thePublic Utilities Commission. Pursuant to this legislation, the Electric Utility is prohibited from renewing its participation inIPP if it remains a coal fueled generating resource. In order to facilitate the continued participation in the IPP, the IPA Board issued the Second Amendatory Power SalesContract, which amended the IPP Contract allowing the plant to replace the coal units with combined cycle natural gasunits by July 1, 2025. On June 16, 2015, the City Council approved the IPP renewal agreements, including the SecondAmendatory Power Sales Contract and the Renewal Power Sales Contract, and authorized participation in the IPPRepower Project for up to 5 percent in generation capacity or 60 MW. The Second Amendatory Power Sales Contractbecame effective March 16, 2016. On January 5, 2017, the Electric Utility executed the Renewal Power Sales Contract and the Electric Utility accepted anoffer of 4.167 percent entitlement or 50 MW generation capacity in the IPP Repower Project based on the 1,200 MWdesigned capacity, which is within the maximum participation level approved by the City Council. The Electric Utility’scorresponding Southern Transmission System allocation is 5.278 percent or approximately 127 MW. Further, under theRenewal Power Sales Contract, the Electric Utility had the right to exit from the Repower Project by no later thanNovember 1, 2019, if it is determined that the Repower Project is not cost beneficial to its customers. On September 11, 2018, the City Council approved “Alternative Repowering” of the IPP Repower Project, which reducedthe design capacity of the future plant from 1,200 MW to 840 MW. On May 7, 2019, the City Council authorized termination of the Renewal Power Sales Contract between the IPA and theElectric Utility effective November 1, 2019, and the Electric Utility’s exit from the IPP Repower Project upon the expirationdate of the current Power Sales Contract on June 15, 2027, due to numerous uncertainties surrounding the IPP RepowerProject. The Electric Utility is a member of SCPPA, a joint powers agency (see Note 9). SCPPA provides for the financing andconstruction of electric generating and transmission projects for participation by some or all of its members. To the extentthe Electric Utility participates in take-or-pay projects developed by SCPPA, it has entered into Power Purchase orTransmission Service Agreements, entitling the Electric Utility to the power output or transmission service, as applicable,and the Electric Utility will be obligated for its proportionate share of the project costs whether or not such generationoutput of transmission service is available.The projects and the Electric Utility’s proportionate share of SCPPA’s obligations, including final maturities and contractexpirations are as follows:ProjectPercent ShareEntitlementFinal MaturityContract ExpirationPalo Verde Nuclear Generating Station%5.4012.3 MW20172030Southern Transmission System %10.20244.0 MW20272027Mead-Phoenix Transmission%4.0018.0 MW20202030Mead-Adelanto Transmission%13.50118.0 MW20202030As part of the take-or-pay commitments with IPA and SCPPA, the Electric Utility has agreed to pay its share of current andlong-term obligations. Management intends to pay these obligations from operating revenues received during the year thatpayment is due. A long-term obligation has not been recorded on the accompanying financial statements for thesecommitments. Take-or-pay commitments terminate upon the later of contract expiration or final maturity of outstandingbonds for each project.68NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)The outstanding debts associated with the take-or-pay obligations have fixed interest rates, which range from 4.00 percentto 5.00 percent. The schedule below details the amount of principal and interest that is due and payable by the ElectricUtility as part of the take-or-pay contract for each project in the fiscal year indicated:IPA1SCPPA2TotalDebt ServicePayment (in thousands)Year Ending June 30,IntermountainPowerProjectSouthernTransmissionSystemAllProjects2025$6,229$6,798$13,02720266,22911,63617,86520279,9149,99919,9132028-7,1587,158Total$22,372$35,591$57,9631The Electric Utility's contract with IPA expires in 2027. The Electric Utility will not be responsible for the proportionate share of the IPA Revenue bondsafter the contract expires.2During fiscal year 2023-24, STS issued 3 Renewal Project bonds. The Electric Utility's contract with STS through SCPPA expires on June 15, 2027.The Electric Utility will be responsible for the proportionate share of the STS bonds up to the July 1, 2027 debt payment date.In addition to debt service, the Electric Utility’s entitlements require the payment of fuel costs, operating and maintenance,administrative and general and other miscellaneous costs associated with the generation and transmission facilitiesdiscussed above. These costs do not have a similar structured payment schedule as debt service varies each year. Thecosts incurred for the years ended June 30, 2024 and 2023, are as follows (in thousands):Fiscal YearIntermountainPowerProject1Palo VerdeNuclearGeneratingStation1SouthernTransmissionSystemMead-PhoenixTransmissionMead-AdelantoTransmissionAllProjects2024$20,106$3,135$3,771$76$640$27,7282023$20,344$3,010$3,839$90$461$27,7441Excludes variable cost.These costs are included in production and purchased power or transmission expense on the Statements of Revenues,Expenses and Changes in Net Position.The Electric Utility has become a Participating Transmission Owner with the California Independent System Operator(CAISO) and has turned over the operational control of its transmission entitlements including the Southern TransmissionSystem, Mead-Phoenix, and Mead-Adelanto Transmission Projects. In return, users of California’s high voltagetransmission grid are charged for, and the Electric Utility receives reimbursement for, transmission revenue requirements,including the costs associated with these three transmission projects.HOOVER UPRATING PROJECTThe Electric Utility’s initial entitlement in the Hoover project through SCPPA terminated on September 30, 2017. On August23, 2016, the City Council approved a 50-year Electric Service Contract (ESC) and an Amended and RestatedImplementation Agreement (IA) with the Western Area Power Administration (Western) Bureau of Reclamation for 30 MWof hydroelectric power. The contract with Western is effective as of October 1, 2017. The ESC extended the ElectricUtility’s 30 MW entitlement in the Hoover project through 2067. The IA is a supplemental agreement to the ESC thatestablishes administrative, budgetary and project oversight by creating project committees and a process for decisionmaking in plant operations.NUCLEAR INSURANCEThe Price-Anderson Act (the Act) requires that all utilities with nuclear generating facilities purchase the maximum privateprimary nuclear liability insurance available ($500 million) and participate in the industry’s secondary financial protectionplan. The secondary financial protection program is the industry’s retrospective assessment plan that uses deferredpremium charges from every licensed reactor owner if claims and/or costs resulting from a nuclear incident at any licensedreactor in the United States were to exceed the primary nuclear insurance at that plant’s site. Effective January 1, 2024,69NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC69 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)NUCLEAR INSURANCE (CONTINUED)the Act limits liability from third-party claims to approximately $16.3 billion per incident. Under the industry-wideretrospective assessment program provided for under the Act, assessments are limited to $165.9 million per reactor foreach nuclear incident occurring at any nuclear reactor in the United States, with payments under the program limited to$24.7 million per reactor, per year, per event to be indexed for inflation every five years. Based on the Electric Utility’sinterest in Palo Verde, the Electric Utility would be responsible for a maximum assessment of $1.6 million, limited topayments of $0.2 million per incident, per year. If the public liability limit above is insufficient, federal regulations mayimpose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactoroperators.RENEWABLE PORTFOLIO STANDARD (RPS)On April 12, 2011, the California Renewable Energy Resources Act (SBX1-2) was signed into law by the Governor, whichofficially created the first set of tiered RPS targets of 20% by 2013, 25% by 2016 and 33% by 2020. SBX1-2 specified thatpublicly owned utilities must meet these defined targets via interim Compliance Period (CP) targets to achieve the end goalof 33% RPS by December 31, 2020 as follows: CP1 - an average of 20 percent of retail sales during the 3-year periodfrom 2011-2013; CP2 – no less than 25 percent of retail sales by December 31, 2016; and CP3 – no less than 33 percentof retail sales by December 31, 2020. The Riverside Public Utilities Board and City Council approved the RPSEnforcement Program required by SBX1-2 on November 18, 2011 and December 13, 2011, respectively, and furtherapproved the Electric Utility’s RPS Procurement Plan (a.k.a. Procurement Policy) implementing the new RPS mandates onMay 3, 2013 and May 14, 2013, respectively. The Electric Utility met the procurement requirements of SBX1-2 for CP1(2011-2013), CP2 (2014-2016), and CP3 (2017-2020). The additional future mandates are expected to be met withresource procurement actions as outlined in the Electric Utility’s RPS Procurement Plan. For calendar year 2023,renewable resources provided 46 percent of retail sales requirements.On October 7, 2015, the Governor signed into law SB 350 increasing the RPS mandate from 33 percent by 2020 to 50percent by December 31, 2030. In addition, SB 350 required that an updated RPS Procurement Policy be approved andadopted before January 1, 2019 and be incorporated into the Electric Utility’s Integrated Resource Plan. An updated 2018Renewable Energy Procurement Policy was adopted by the Board and City Council on September 10, 2018 and October9, 2018, respectively. The Electric Utility expects to be able to substantially meet the increased RPS mandates imposed bySB 350 with the actions described in the updated procurement policy and the portfolio of renewable resources outlinedbelow.On September 10, 2018, the 100 Percent Clean Energy Act of 2018 (SB 100) was signed into law by the CaliforniaGovernor. This bill further increases the RPS goals of SBX1-2 and SB 350 while maintaining the 33 percent RPS target byDecember 31, 2020, but modifying the RPS percentages to be 44 percent by December 31, 2024, 52 percent byDecember 31, 2027, 60 percent by December 31, 2030, with an end goal of 100 percent of total retail sales of electricity inCalifornia generated from eligible renewable energy resources and zero-carbon resources by December 31, 2045. It isexpected that the California Energy Commission will have further guidance and enforcement procedures for publiclyowned utilities to meet these increased mandates. The Electric Utility will continue to monitor the outcome and impacts ofany upcoming workshops and regulations in meeting the new requirements.In an effort to increase the share of renewables in the Electric Utility’s power portfolio, the Electric Utility entered into powerpurchase agreements (PPA) and power sales agreements (PSA) with various entities described below in general on a“take-and-pay” basis. The contracts in the following tables were executed as part of compliance with RPS mandates.70NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)RENEWABLE PORTFOLIO STANDARD (RPS) (CONTINUED)Long-term renewable PPAs and PSAs in operation (dollars in thousands):SupplierTypeMaximumContract1ContractExpirationEstimatedAnnualCost for2024WintecWind1.3MW02/19/2024$151WKN WagnerWind6.0MW12/22/20321,375Terraform Power - AP North LakePhotovoltaic20.0MW08/11/20404,992Onward Energy - Columbia IIPhotovoltaic11.1MW12/22/20342,320Salka Cabazon HoldCo LLC - GPS Cabazon WindWind39.0MW12/31/20274,311Arevon - Kingbird Solar B, LLCPhotovoltaic14.0MW12/31/20362,875AES - Summer SolarPhotovoltaic10.0MW12/31/20411,752AES - Antelope Big Sky RanchPhotovoltaic10.0MW12/31/20411,752AES - Antelope DSR 1 SolarPhotovoltaic25.0MW12/19/20363,836Arevon - Tequesquite Landfill SolarPhotovoltaic7.3MW12/31/20401,448Roseburg Forest Products2BiomassN/A02/16/2026179CalEnergy - Salton Sea PortfolioGeothermal86.0MW12/31/203956,609Atlantica - Coso GeothermalGeothermal10.0MW12/31/20416,067Total239.7MW$87,667All contracts are contingent on energy delivered from specific related generating facilities. The Electric Utility has no commitment to pay any amountsexcept for energy delivered on a monthly basis from these facilities except for any economic curtailments directed by the Electric Utility.2This supply is only available to satisfy SB 859 requirements.Long-term renewable PPAs with expected delivery:SupplierTypeMaximumContract1ExpectedDeliveryEnergy Delivery NoLater ThanContract Term InYearsSunZia Wind Power Co.Wind125.0 MW03/31/202603/31/202715Atlantica - Coso GeothermalGeothermal20.0 MW01/01/202701/01/202715Total145.0 MW1All contracts are contingent on energy delivered from specific related generating facilities. The Electric Utility has no commitment to pay any amountsexcept for energy delivered on a monthly basis from these facilities except for any economic curtailments directed by the Electric Utility.On May 20, 2003, the Electric Utility and Salton Sea Power LLC (Salton Sea) entered into a ten-year PPA for 20 MW ofgeothermal energy. On August 23, 2005, the City Council approved an amendment to the PPA that increased the amountof renewable energy available to the Electric Utility from 20 MW to 46 MW effective June 1, 2009 through May 31, 2020.On May 14, 2013, the City Council approved a new 25-year PPA with CalEnergy, the parent of Salton Sea, for additionalrenewable geothermal power. The PPA provides power from a portfolio of ten geothermal generating units, instead of asingle generating unit, with an increasing amount of delivery that started with 20 MW in 2016, increasing to 40 MW in2019, and 86 MW in 2020. The initial price under the agreement was $72.85 per megawatt-hour (MWh) in calendar year2016, which will escalate at 1.5 percent annually for the remaining term of the agreement. Similar to other renewablePPAs, the Electric Utility is only obligated for purchases of energy delivered to the City.Concurrently, the pricing under the Salton Sea PPA was amended to conform to pricing in the new PPA with CalEnergythrough the remaining term of the Salton Sea PPA. The pricing under the Salton Sea PPA increased by approximately$7.57 per MWh, commencing July 1, 2013 to $69.66 per MWh, with an escalation of 1.5 percent annually thereafter,reflecting the exchange of benefits for a substantially lower pricing under the new PPA. The cost increase under the SaltonSea PPA and accrual of the prepayment ended as of May 31, 2020. As of June 30, 2024 and 2023, the Electric Utility’sprepayment of future contractual obligations was $11,689 and $12,330, respectively. This prepayment is recorded on theStatements of Net Position as unamortized purchased power, to be amortized over the term of the CalEnergy PPA. TheCalEnergy PPA commenced in February 2016. As of June 30, 2024 and 2023, the Electric Utility has recorded $641 and$641, respectively, in amortization related to the unamortized purchased power.NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC71 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)RENEWABLE PORTFOLIO STANDARD (RPS) (CONTINUED)On January 28, 2003, the Electric Utility entered into a 15-year renewable PPA with Wintec Energy, Ltd (Wintec) to71RD (RPS) (CONTINUED)purchase all of the energy output generated by Wintec’s wind powered electric generating units with capacity up to 5 MW.Due to unforeseen circumstances, Wintec was only able to generate capacity totaling 1.3 MW. On November 15, 2005,the City Council approved an amendment to the original agreement, reducing the capacity to 1.3 MW. The amendedcontract with Wintec terminated in December 2018, however, on February 12, 2019, the City Council approved anextension to the amended agreement for an additional five years for a reduced price of $35.77 per MWh. On February 19,2024, this agreement term expired and was not extended.On October 16, 2012, the Electric Utility entered into a 25-year PPA with AP North Lake, LLC (AP North) for 20 MW ofsolar photovoltaic energy generated by a new facility located in the City of Hemet, California. The AP North Lake Projectbecame fully operational in August 2015. The project is expected to generate 55,000 MWh of renewable energy per yearat a levelized cost of $95 per MWh for the term of the PPA. After a series of ownership changes, AP North Lake is nowowned by Terraform Power.On December 20, 2012, the Electric Utility entered into a 20-year PPA with WKN Wagner, LLC (WKN) for up to 6 MW ofrenewable wind energy and renewable energy credits from the WKN Wagner wind project in Palm Springs, California.WKN is expected to generate 21,000 MWh of renewable energy annually at a levelized cost of $73 per MWh.On January 17, 2013, the Electric Utility entered into two 25-year PSAs with SCPPA for a combined total of 20 MW of solarphotovoltaic energy generated by two facilities to be built in the City of Lancaster by Silverado Power, which later changedits name to sPower after a series of ownership changes. The two projects are referred to as Antelope Big Sky Ranch andSummer Solar, each rated at 20 MW. The Electric Utility has a 50 percent share of the output from each project throughSCPPA, which has two 20 MW PPAs with sPower. Summer Solar became commercially operational on July 25, 2016, andAntelope Big Sky Ranch became commercially operational on August 19, 2016. The Electric Utility’s share from the twoprojects is 55,000 MWh of renewable energy per year. The price under the agreements is $71.25 per MWh over the termof the agreements. In 2021, sPower merged with the AES Corporation, resulting in AES becoming the new parentcompany.On September 19, 2013, the Electric Utility entered into a 20-year PSA with SCPPA for 14 MW of solar photovoltaic energygenerated by a facility to be built by First Solar in Kern County, California. The project is referred to as the Kingbird B SolarPhotovoltaic Project, with a nameplate capacity of 20 MW. The Electric Utility has a 70 percent share of the output fromthe project through SCPPA, which has a 20 MW PPA with Kingbird Solar B, LLC, which was acquired by Capital Dynamicsin 2018. The project became commercially operational on April 30, 2016. The Electric Utility’s share from the project isapproximately 35,000 MWh of renewable energy per year with an all-in price for energy, capacity and environmentalattributes of $68.75 per MWh over the term of the agreement. In 2022, Capital Dynamics was acquired by Arevon.On September 19, 2013, the Electric Utility entered into a 20-year PSA with SCPPA for 11.1 MW of solar photovoltaicenergy generated by a facility to be built by Recurrent Energy in Kern County, California. The project, referred to asColumbia Two Solar Photovoltaic Project, has a nameplate capacity of 15 MW. On March 14, 2014, a Consent andAgreement was entered into by SCPPA consenting to the transfer of ownership of the Columbia Two project fromRecurrent Energy to Dominion Resources. The Columbia Two Project completed construction and achieved commercialoperation in December 2014. The Electric Utility has a 74.3 percent share (11.1 MW) of the output from the Columbia TwoProject through SCPPA, which has a 15 MW PPA with Dominion Resources. The Electric Utility’s share of Columbia Twois approximately 33,000 MWh of renewable energy per year with an all-in price for energy, capacity and environmentalattributes of $69.98 per MWh over the term of the agreement. In 2021, Onward Energy, LLC became the new parentcompany of Columbia Two.On December 6, 2013, the Electric Utility and FPL Energy Cabazon Wind, LLC (Cabazon Wind) entered into a 10-yearPPA for 39 MW of renewable wind energy from the Cabazon Wind Energy Center near Cabazon, California. CabazonWind is an existing renewable resource that has been in commercial operation since 1999. SCE purchased the output ofthe facility through December 2014. At the expiration of SCE’s contract, Cabazon Wind entered into new interconnectionand generation agreements with CAISO and SCE. The developer completed the implementation of the transition to theElectric Utility as of January 1, 2015. Delivery under the PPA commenced on January 1, 2015. The project is expected togenerate 71,200 MWh of renewable energy per year with an all-in price for energy, capacity and environmental attributesof $59.30 per MWh over the term of the agreement. In 2018, after it was acquired by GlidePath Power Solutions, FPLEnergy Cabazon Wind, LLC changed its name to GPS Cabazon Wind, LLC. On September 1, 2023, Salka CabazonHoldCo LLC purchased the GPS Cabazon Wind project and assumed the remaining term of the Agreement.NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)RENEWABLE PORTFOLIO STANDARD (RPS) (CONTINUED)On March 11, 2014, the Electric Utility and Solar Star California XXXI, LLC (Solar Star) entered into a 25-year PPA for 7.3RD (RPS) (CONTINUED)MW of solar photovoltaic energy generated by a facility to be built on the City-owned Tequesquite Landfill. The project wasfully commissioned and operational on September 30, 2015 and is expected to generate approximately 15,000 MWh ofrenewable energy per year. The all-in price for energy, capacity and environmental attributes is $81.30 per MWh,escalating at 1.5 percent annually. In 2018, Capital Dynamics became the new parent company of Solar Star afteracquiring it from SunPower. In 2022, Capital Dynamics was acquired by Arevon.On July 16, 2015, the Electric Utility entered into a 20-year PSA with SCPPA for 25 MW of solar photovoltaic energygenerated by sPower’s Antelope DSR Solar 1 PV Project in the City of Lancaster, California. The Electric Utility has a 50percent share of the output from the project through SCPPA, which has a 50 MW PPA with sPower. The project becamecommercially operational on December 20, 2016. The Electric Utility’s share of Antelope DSR Solar 1 is expected togenerate approximately 71,000 MWh of renewable energy per year with an all-in price for energy, capacity andenvironmental attributes of $53.75 per MWh over the term of the agreement. In 2021, sPower merged with the AESCorporation, resulting in AES becoming the new parent company.On January 15, 2021, the Electric Utility entered into a 20-year PSA with SCPPA for 10 MW for the first 5 years of thecontract and 30 MW for the remaining 15 years of the contract of geothermal energy generated by Atlantica's CosoGeothermal project. The Electric Utility has partnered with the cities of Banning and Pasadena to share SCPPA'scontracted capacity. The project began delivery on January 1, 2022. The Electric Utility's share of Coso Geothermal isexpected to provide 87,500 MWh annually in the first 5 years of the term and 268,300 MWh in the remainder of the term atan all-in price for energy, capacity, Resource Adequacy, and environmental attributes of $69.00 per MWh over the term ofthe agreement.On February 16, 2021, the Electric Utility entered into a 5-year SB 859 Purchase Agreement with Roseburg ForestProducts Co for the remaining 0.5 MW of SB 859 compliance. The Electric Utility has a 4.48 percent share of the output ofthe project along with SCPPA, Modesto Irrigation District, Sacramento Municipal Utility District, and Turlock IrrigationDistrict, for a total capacity of 11 MW with Roseburg. The project began delivery on February 16, 2021. The price for theSB 859 compliant capacity is $46.00 per MWh over the term of the agreement.On November 8, 2023, the Electric Utility entered into a 15-year Renewable Power Purchase and Sale Agreement withSunZia Wind Power Co. LLC for 125 MW from the wind-powered electricity generating facility located in New Mexico. Thefacility is expected to provide an additional 369,000 to 390,000 MWh per year of long-term renewable energy to Riverside.The facility will provide energy, capacity, resource adequacy, and environmental attributes at an all-in price of $59.50 perMWh throughout the term of the agreement. The project is expected to begin delivery by March 31, 2026 with anenforceable guaranteed delivery date of September 30, 2026.On November 16, 2017, the Electric Utility entered into a 5-year PSA with SCPPA for 0.8 MW of biomass energygenerated by American Renewable Power (ARP) - Loyalton Biomass Project. The Electric Utility has a 4.48 percent shareof the output of the project through SCPPA, which, along with Imperial Irrigation District, Modesto Irrigation District,Sacramento Municipal Utility District, and Turlock Irrigation District, has an 18 MW PPA with ARP-Loyalton. The projectbegan delivery on April 20, 2018. The Electric Utility’s share of ARP Loyalton was expected to generate 6,358 MWh ofrenewable energy per year with an all-in price for energy, capacity and environmental attributes of $97.50 per MWh overthe term of the agreement. On February 18, 2020, ARP Loyalton Cogen, LLC filed Chapter 11 bankruptcy. On March 18,2020, the bankruptcy was converted to Chapter 7. On April 30, 2020, the bankruptcy court approved the sale of the ARPLoyalton project to Sierra Valley Enterprise. On April 19, 2023, the agreement expired, fulfilling its obligations under SB869. On April 30, 2024, the courts approved the bankruptcy and settlement, which required the trustee to reimburse all ofthe legal expenses throughout the bankruptcy process.CAP-AND-TRADE PROGRAMAssembly Bill (AB) 32, enacted in 2006, mandated that the California Air Resources Board (CARB) develop regulations forthe reduction of greenhouse gas (GHG) emissions to the 1990 levels by the year 2020. Subsequently, SB 32, enacted in2016, extended the requirements of AB 32 and codified that it was the State’s goal to reduce GHG emissions to 40%below 1990 levels by the year 2020. AB 398 was then enacted in 2017 clarifying that it was the State legislature’s intent tocontinue the Cap-and-Trade Program and regulations until 2030. In January 2013, emission compliance obligationsdeveloped by CARB began under the Cap-and-Trade Program (Program). This Program requires electric utilities to haveGHG allowances on an annual basis to offset GHG emissions associated with generating electricity. To ease the transitionNOTES TO THE FINANCIAL STATEMENTS: ELECTRIC73 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)CAP-AND-TRADE PROGRAM (CONTINUED)and mitigate the rate impacts to retail customers, CARB will allocate certain amounts of GHG allowances at no cost toelectrical distribution utilities. The Electric Utility’s free allocation of GHG allowances is expected to be sufficient to meetM (CONTINUED)the Electric Utility’s direct GHG compliance obligations.At times, the Electric Utility may have allocated allowances in excess of its compliance obligations that can be sold into theCARB quarterly auctions. In fiscal years ended June 30, 2024 and 2023, the Electric Utility received $15,683 and $18,317,respectively, in proceeds related to the sale of the GHG allowances, which are included on the Statements of Revenues,Expenses and Changes in Net Position as other operating revenue. The Electric Utility has established a restrictedRegulatory Requirement reserve to comply with regulatory restrictions and governing requirements related to the use ofthe GHG proceeds. The available funds are to be utilized for qualifying projects, consistent with the goals of AB 32 tobenefit the retail ratepayers. The balance in the Regulatory Requirement reserve was $29,845 and $21,707 as of June 30,2024 and 2023, respectively.The Electric Utility also purchases GHG allowances, which can be used in future periods for GHG compliance regulations.The balance of purchased GHG allowances was $1,464 and $1,464 as of June 30, 2024 and 2023, and is recorded asinventory on the Statements of Net Position.LOW CARBON FUEL STANDARD PROGRAMAB 32, enacted in 2006, mandated that the California Air Resources Board (CARB) develop regulations for the reductionof greenhouse gas (GHG) emissions to the 1990 levels by the year 2020. Subsequently, SB 32, enacted in 2016, extendedthe requirements of AB 32 and codified that it was the State’s goal to reduce GHG emissions to 40% below 1990 levels bythe year 2020. Similar to the Cap-and-Trade Program, the Low Carbon Fuel Standard (LCFS) Program is a keycomponent of the market mechanisms authorized by these bills to achieve the State’s GHG emissions reduction goals.The LCFS regulation was initiated in 2009 and approved in 2010 by CARB. The program then underwent some litigation inthe State of California and the regulation was re-adopted in 2015 with modifications and went into effect in 2016. LCFSseeks to reduce the carbon intensity (CI) of fuels used for transportation by establishing an annual CI target. Fuels thathave a CI greater than the target have a compliance obligation and are required to turn in LCFS credits; fuels with a CIlower than the target may generate credits.Electricity is considered a fuel subject to the program when it is used as a transportation fuel in electric vehicles. However,because the CI of electricity is substantially lower than the annual CI targets under the program, electricity is a fuel thatgenerates LCFS credits and participation in the Program is voluntary. The City opted into the LCFS program in March2018 and began generating LCFS credits for the first quarter of 2018. These credits are associated with two sources –unmetered electricity used to charge residents’ electric vehicles at their homes (residential base credits) and from electricforklifts charging at private businesses (forklift credits). CARB calculates the credits that the Electric Utility receives andthe Electric Utility submits reports quarterly to receive the credits.The LCFS regulation was amended in 2018 and required that electric utilities that have opted into the LCFS Programparticipate in and manage a statewide point-of-sale rebate program for new electric vehicles. This program is called theCalifornia Clean Fuel Reward Program (CFR) and the City joined the program in May 2020. To fund the program, electricutilities are required to contribute proceeds received from the sales of residential base credits beginning with the creditsthe Electric Utility received in Q4 2019 (generated from electricity used for transportation in Q2 2019). Residential basecredits the Electric Utility received prior to that time are not subject to the contribution requirements. Additionally, a “start-up” contribution from proceeds was required to be submitted by January 31, 2021. After the initial deposit of funds inNovember 2020, deposits to the CFR program are required by March 31 annually.In fiscal years ended June 30, 2024 and 2023, the Electric Utility’s proceeds from the sale of LCFS credits was $874 and$683, respectively. These proceeds are included on the Statements of Revenues, Expenses and Changes in Net Positionas other operating revenue. The Electric Utility has established a restricted Regulatory Requirement reserve to comply withregulatory restrictions and governing requirements related to the use of the LCFS proceeds. The available funds are to beutilized for qualifying programs that support the Electric Utility’s customers who are existing and future electric vehicleowners. Total expenses for qualifying programs as of June 30, 2024 and 2023 was $356 and $194, respectively. Thebalance in the Regulatory Requirement reserve as of June 30, 2024 and 2023 was $4,415 and $3,795, respectively.NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.COMMITMENTS (CONTINUED)CONSTRUCTION COMMITMENTSAs of June 30, 2024, the Electric Utility had commitments (encumbrances) of approximately$76,999 with respect toongoing capital projects, of which $69,136 is expected to be funded by bonds, $7,819 to be funded by unrestricted cashreserves, and $44 to be funded by restricted cash reserves.FORWARD PURCHASE/SALE AGREEMENTSIn order to meet seasonal energy needs and summer peaking requirements, the Electric Utility contracts on a monthlyand/or quarterly basis for the purchase or sale of natural gas, electricity and/or capacity products on a one to four yearforward time horizon. As of June 30, 2024, the Electric Utility has net natural gas and electricity commitments for fiscalyear 2025 and thereafter of approximately $102,311, with a market value of $85,038. It should be noted that the marketvalue can and typically does change on a daily basis. 12.LITIGATIONThe Electric Utility is a defendant in various lawsuits arising in the normal course of business. Present lawsuits and otherclaims against the Electric Utility are incidental to the ordinary course of operations of the Electric Utility and are largelycovered by the City’s self-insurance program. In the opinion of management and the City Attorney, such claims andlitigation will not have a materially adverse effect upon the financial position or results of operation of the Electric Utility.Contractual and litigation matters of the Electric Utility relating to SONGS are contained in Note 10.On September 12, 2018, a petition for writ of mandate entitled Parada v. City of Riverside (“Parada II”) was filed againstthe City seeking to invalidate, rescind and void, under Proposition 26, the Electric System’s rates approved by City Councilon May 22, 2018, which took effect on January 1, 2019, by challenging the portion of the electric rates that are attributableto the General Fund. The petition did not seek any monetary relief from the General Fund. The trial court divided the caseinto two stages for hearings: a liability phase and a damages phase. On April 17, 2020, the Court in the liability phase ofParada II litigation entered a tentative ruling finding the City’s electric rates attributable to the General Fund transfer violateArticle XIII C of the California Constitution. The formal hearing on the matter took place on June 5, 2020, but the Courtasked for further briefing on the issue of whether or not the plaintiffs failed to exhaust their administrative remedies. OnOctober 9, 2020, the Court confirmed its tentative ruling and entered an order denying the City’s request for interlocutoryremand. The court had set a hearing for February 24, 2021, to set a briefing schedule for determining appropriateremedies/damages in the case. The City expected the second phase of the trial relating to plaintiffs’ available remedies tooccur in the second quarter of 2021. The ruling by the Court in Parada II was anticipated to likely have a material adverse impact on the City’s General Fund.The General Fund receives approximately $40 million annually (up to the maximum amount of 11.5% of Electric Fundrevenues) from the Electric Fund. Based on the Court’s order in the liability phase of the trial, approximately $19-32 millionof the General Fund transfer is potentially attributable to rate payer revenue that was not approved by the voters. However,that amount will be determined during the damages phase of the trial. Additionally, the City might have been required torefund rate payers for the portions of the rates that were determined to violate Article XIII C of the California Constitutionfrom the date the writ of mandate was filed. However, the trial court did not issue any ruling as to what the amount of anydamages would be. Based on the Court’s order in the liability phase of the trial, the City estimated that the amount of a refund would be $19 to$32 million per year, beginning January 1, 2019, until date of settlement or issuance of a final, non-appealable judgment bythe trial court after anticipated appeals are resolved. This amount could vary depending upon whether or not the Citydecides to repeal and replace the challenged rates pending appeal. On May 17, 2021, the City and the Paradas entered into a conditional settlement agreement. This settlement wasconditioned on: (1) the Riverside City Council’s placement of a ballot measure on City ballots in November 2021 toapprove the City’s General Fund Transfer practices as a general tax (“Ballot Measure”); and (2) voter approval of the BallotMeasure. The Riverside City Council placed the Ballot Measure on the ballot for the November 2, 2021 election. TheParties stayed the Parada lawsuit until certification of the results of the Ballot Measure. If voters approved the BallotMeasure, the City would refund to customers of its electric utility an amount equal to $24 million less the amount awardedto Plaintiffs’ counsel in fees, paid over a five year period beginning no later than February 1, 2022. If voters did not approvethe Ballot Measure, this litigation would then resume. 75NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC75 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 12.LITIGATION (CONTINUED)On or about September 16, 2021, a petition for writ of mandate entitled Riversiders Against Increased Taxes v. City ofRiverside, et al. (“RAIT lawsuit”) was filed against the City challenging the Ballot Measure on the grounds that the BallotMeasure cannot be adopted at the November 2021 election because that election is a “special” election and underProposition 218, a ballot measure to impose a general tax can only be submitted to voters at a general election. OnNovember 9, 2021, the court set a trial date for the RAIT lawsuit for January 7, 2022 and ordered a stay of the certificationof the Ballot Measure Election results pending the January 7th hearing but did not otherwise delay or cancel the electionfor the Ballot Measure.The election was held on November 2, 2021, and the Measure C was approved by voters, with 54.52% voting in favor. On April 26, 2022 the RAIT lawsuit trial court determined that the November 2021 election was a “special election” ratherthan a “general election” and therefore did not comply with Proposition 218. The RAIT lawsuit trial court further ruled that itlacked power to enjoin the certification of election results or to otherwise invalidate the election. Both sides appealed thatruling. On July 25, 2024, the appellate ruled in favor of the City and against RAIT, holding that the City conducted a properelection in compliance with Proposition 218 and 26.On May 12, 2022, the City and the Paradas amended the May 17, 2021 Settlement Agreement, with the followingadditional terms: (a) City agreed to start making refunds to ratepayers by October 1, 2022; (b) if the City prevailed in theappeal of the trial court’s decision in the RAIT lawsuit, no additional refund would be due to the ratepayers; (c) if the Citydid not prevail in the appeal of the trial court’s decision in the RAIT lawsuit, an additional refund would be implemented inthe amount of $705,882 per month, from November, 2021 up to when the City either (i) sets new electric rates; (ii) votersapprove a valid ballot measure for the GFT or (iii) the City otherwise stops collecting the electric GFT. The Parada lawsuitwas dismissed on May 13, 2022. The City Council adopted a resolution certifying the results of the Measure C election on July 19, 2022. The plaintiffs fromthe RAIT lawsuit sought to intervene in the Parada lawsuit and set aside this dismissal. On August 3, 2022, the Paradatrial court refused to set aside the dismissal. The City has now begun to implement the settlement agreement. However,because the appellate court ruled in favor of the City, no additional refunds are owed to ratepayers by the City. 76NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 13.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTSFor the year ended June 30, 2023, the financial statements include the adoption of GASB Statement No. 96, Subscription-Based Information Technology Agreements (SBITA). This Statement defines a SBITA as a contract that conveys control ofthe right to use another party's information technology software, alone or in a combination with tangible capital assets, asspecified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer tothe disclosures below.LEASES PAYABLELeases are financings of the right-to-use an underlying asset and a lessee is required to recognize a lease liability and anintangible lease asset.The Electric Utility had 21 and 23 leases as Lessee for the use of buildings and various pieces of machinery andequipment for the years ended June 30, 2024 and 2023, respectively. The Electric Utility is required to make principal andinterest payments for these leases through fiscal year 2029. An initial lease liability was recorded in the amount of $625.As of June 30, 2024 and 2023, the value of the lease liability were $294 and $362, respectively. The leases had an interestrate of 0.52% to 2.50% and 0.52% for fiscal years ended June 30, 2024 and 2023, respectively. The value of the lease assets were $613 and $628 with accumulated amortization of $326 and $273 for the fiscal yearsended June 30, 2024 and 2023, as shown on the Asset Class activities tables found below.Amount of Lease Assets by MajorClasses of Underlying Asset as ofJune 30, 2024Asset ClassLease AssetValueAccumulatedAmortizationBuilding$348$(223)Machinery and Equipment265(103)Total$613$(326)Amount of Lease Assets by MajorClasses of Underlying Asset as ofJune 30, 2023Asset ClassLease AssetValueAccumulatedAmortizationBuilding$348$(149)Machinery and Equipment280(124)Total$628$(273)The following is a summary of changes in leases liability during the fiscal years ended June 30, 2024 and 2023BalanceAs of6/30/2022AdditionsReclassReductionsBalanceAs of6/30/2023AdditionsReclassReductionsBalanceAs of6/30/2024Due WithinOne YearLease Liability$497$-$-$(135)$362$123$-$(191)$294$13277NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC77 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 13.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)As of June 30, 2024, lease liability principal and interest payments consist of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2025$132$3$135202692294202725227202825126202920-20Total$294$8$302As of June 30, 2023, lease liability principal and interest payments consisted of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2024$137$2$13920251361137202689-89Total$362$3$365LEASES RECEIVABLELeases are financings of the right-to-use an underlying asset and a lessor is required to recognize a lease receivable and adeferred inflow of resources.The Electric Utility has consistently maintained 11 leases as a Lessor for the use of various pieces of building andequipment for the fiscal years ended June 30, 2024 and 2023. At June 30, 2024 and 2023 the terms of these leases rangefrom 6 to 30 years beginning on the contract commencement date. For the fiscal years ended June 30, 2024 and 2023,the value of the lease receivables were $12,412 and $11,766. with interest rates ranging from 1.24% to 3.23% and 0.52%to 1.68%, respectively. As of June 30, 2024 and 2023, the value of the deferred inflow of resources, were $11,741 and$11,394 with recognized lease revenue of $1,645 and $1,583, respectively. As of June 30, 2024, lease receivable principal and interest payments consist of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2025$1,343$182$1,52520261,5061661,67220271,6571471,80420281,4011291,53020291,0081141,1222030-20343,1653503,5152035-20391,9061182,0242040-20444265431Total$12,412$1,211$13,62378NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 13.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)LEASES RECEIVABLE (CONTINUED)As of June 30, 2023, lease receivable principal and interest payments consisted of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2024$1,359$131$1,49020251,4121181,53020261,3651061,47120271,436941,53020281,165831,2482029-20332,4163062,7222034-20381,8191381,9572039-204379415809Total$11,766$991$12,757SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS PAYABLEThe Electric Utility had 4 and 2 subscription-based information technology arrangement (SBITA) for the use of varioussoftware for the fiscal years ended June 30, 2024 and 2023, respectively. The Electric Utility is required to make principaland interest payments for the leases through fiscal year 2026. An initial lease liability was recorded in the amount of $32.As of June 30, 2024, and 2023, the value of the subscription liability was $96 and $49, the subscriptions had an interestrate of 0.52 to 2.50% and 0.52%, respectively. As of June 30, 2024 and 2023, the value of the subscription assets were$231 and $93 with accumulated amortization of $108 and $43.As of June 30, 2024 and 2023, the Asset Class activities tables were as follows:Amount of SBITA Assets by MajorClasses of Underlying Asset as ofJune 30, 2024Asset ClassSBITA AssetValueAccumulatedAmortizationSoftware$231$(108)Total$231$(108)Amount of SBITA Assets by MajorClasses of Underlying Asset as ofJune 30, 2023Asset ClassSBITA AssetValueAccumulatedAmortizationSoftware$93$(43)Total$93$(43)79NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC79 ELECTRIC UTILITY:NOTES TO THE FINANCIAL STATEMENTS 13.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)Subscription-Based Information Technology Arrangements Payable (CONTINUED)The following is a summary of changes in SBITA liability during the fiscal years ended June 30, 2024 and 2023:BalanceAs of6/30/2022AdditionsReclassReductionsBalanceAs of6/30/2023AdditionsReclassReductionsBalanceAs of6/30/2024Due WithinOne YearSBITA Liability$94$-$-$(45)$49$134$-$(87)$96$50As of June 30, 2024, SBITA liability principal and interest payments consist of the following:Fiscal YearPrincipalInterestTotal Payments2025$50$1$51202646147Total$96$2$98As of June 30, 2023, SBITA liability principal and interest payments consisted of the followingFiscal YearPrincipalInterestTotal Payments2024$42$-$4220257-7Total$49$-$49 80NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
Reporting period 2024 2023 2022 2021 2020Measurement period 2023 2022 2021 2020 2019Electric Utility's Proportion of the Net Pension Liability 28.53% 29.42% 29.56% 32.68% 30.73%Electric Utility's Proportionate Share of the Net Pension Liability 44,227$ 38,748$ (26,219)$ 39,233$ 89,792$ Electric Utility's Covered Payroll 40,566$ 38,265$ 38,794$ 42,966$ 39,605$ Electric Utility's Proportionate Share of the Net Pension Liability as a Percentage of Covered Payroll 109.03% 101.26% -67.59% 91.31% 226.72%Electric Utility's Proportionate Share of the Fiduciary Net Position as a Percentage of the Electric Utility's Total Pension Liability 90.73% 91.80% 105.72% 91.95% 79.57%Notes to Schedule:Benefit Changes:There were no changes in benefits.Changes in Assumptions:From fiscal year June 30, 2015 to June 30, 2016:GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension planinvestment expense but without reduction for pension plan administrative expense. The discount rate of 7.50% used forthe June 30, 2014 measurement date was net of administrative expenses. The discount rate of 7.65% used for theJune 30, 2015 measurement date is without reduction of pension plan administrative expense.From fiscal year June 30, 2016 to June 30, 2017:There were no changes in assumptions.From fiscal year June 30, 2017 to June 30, 2018:The discount rate was reduced from 7.65% to 7.15%.From fiscal year June 30, 2018 to June 30, 2022:There were no significant changes in assumptions.From fiscal year June 30, 2022 to June 30, 2023:The discount rate and long-term rate of return decreased from 7.15% to 6.90% and the inflation rate decreased from2.50% to 2.30%.From fiscal year June 30, 2023 to June 30, 2024:There were no significant changes in assumptions. (amounts expressed in thousands)ELECTRIC UTILITYSCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITYAS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS (1) 81REQUIRED SUPPLEMENTARY INFORMATION: ELECTRIC81
Reporting period 2019 2018 2017 2016 2015Fiscal Year Ended 2018 2017 2016 2015 2014Electric Utility's Proportion of the Net Pension Liability 30.32% 32.04% 31.08% 31.96% 31.14%Electric Utility's Proportionate Share of the Net Pension Liability 84,468$ 108,886$ 96,193$ 77,907$ 71,773$ Electric Utility's Covered Payroll 36,976$ 37,686$ 36,834$ 35,437$ 34,256$ Electric Utility's Proportionate Share of the Net Pension Liability as a Percentage of Covered Payroll 228.44% 288.93% 261.15% 219.85% 209.52%Electric Utility's Proportionate Share of the Fiduciary Net Position as a Percentage of the Electric Utility's Total Pension Liability 79.64% 75.23% 75.47% 79.93% 80.86%Notes to Schedule:Benefit Changes:There were no changes in benefits.Changes in Assumptions:From fiscal year June 30, 2015 to June 30, 2016:GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension planinvestment expense but without reduction for pension plan administrative expense. The discount rate of 7.50% used forthe June 30, 2014 measurement date was net of administrative expenses. The discount rate of 7.65% used for theJune 30, 2015 measurement date is without reduction of pension plan administrative expense.From fiscal year June 30, 2016 to June 30, 2017:There were no changes in assumptions.From fiscal year June 30, 2017 to June 30, 2018:The discount rate was reduced from 7.65% to 7.15%.From fiscal year June 30, 2018 to June 30, 2022:There were no significant changes in assumptions.From fiscal year June 30, 2022 to June 30, 2023:The discount rate and long-term rate of return decreased from 7.15% to 6.90% and the inflation rate decreased from2.50% to 2.30%.From fiscal year June 30, 2023 to June 30, 2024:There were no significant changes in assumptions. (amounts expressed in thousands)ELECTRIC UTILITYSCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY (CONTINUED)AS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS (1) 82REQUIRED SUPPLEMENTARY INFORMATION: ELECTRIC
ELECTRIC UTILITYSCHEDULE OF CONTRIBUTIONSAS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS (1)2024 2023 2022 2021 2020Contractually Required Contribution (Actuarially Determined) 6,060$ 8,316$ 8,041$ 7,768$ 12,707$ Contributions in Relation to the Actuarially Determined Contributions (6,060) (8,316) (8,041) (7,768) (78,167) Contribution Deficiency (Excess) -$ -$ -$ -$ (65,460)$ Covered Payroll 44,881$ 40,566$ 38,265$ 38,794$ 42,966$ Contributions as a Percentage of Covered Payroll 13.50% 20.50% 21.01% 20.02% 29.58%Notes to Schedule:Valuation Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017Methods and Assumptions Used to Determine Contribution Rates:Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry AgeAmortization Method (1) (1) (1) (1) (1)Asset Valuation Method Fair Value Fair Value Fair Value Fair Value Fair ValueInflation 2.300% 2.300% 2.500% 2.500% 2.625%Salary Increases (2) (2) (2) (2) (2)Investment Rate of Return 6.90% (3) 6.90% (3) 7.00% (3) 7.00% (3) 7.25% (3)Retirement Age (4) (4) (4) (4) (4)Mortality (5) (5) (5) (5) (5)(1) Level percentage of payroll, closed(2) Depending on age, service, and type of employment(3) Net of pension plan investment expense, including inflation(4) Classic: 50-67 and PEPRA: 52-67(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study adopted by the CalPERS Board. (amounts expressed in thousands)
83REQUIRED SUPPLEMENTARY INFORMATION: ELECTRIC83
ELECTRIC UTILITYSCHEDULE OF CONTRIBUTIONS (CONTINUED)AS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS (1)2019 2018 2017 2016 2015Contractually Required Contribution (Actuarially Determined) 10,598$ 9,080$ 8,635$ 7,734$ 6,731$ Contributions in Relation to the Actuarially Determined Contributions (10,598) (9,080) (9,764) (9,146) (8,308) Contribution Deficiency (Excess) -$ -$ (1,128)$ (1,411)$ (1,577)$ Covered Payroll 39,605$ 36,976$ 37,686$ 36,834$ 35,437$ Contributions as a Percentage of Covered Payroll 26.76% 24.56% 22.91% 21.00% 18.99%Notes to Schedule:Valuation Date 6/30/2016 6/30/2015 6/30/2014 6/30/2013 6/30/2012Methods and Assumptions Used to Determine Contribution Rates:Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry AgeAmortization Method (1) (1) (1) (1) (1)Asset Valuation Method Fair Value Fair Value Fair Value Fair Value 15 YearSmoothedMarket MethodInflation 2.75% 2.75% 2.75% 2.75% 2.75%Salary Increases (2) (2) (2) (2) (2)Investment Rate of Return 7.375% (3) 7.50% (3) 7.50% (3) 7.50% (3) 7.50% (3)Retirement Age (4) (4) (4) (4) (4)Mortality (5) (5) (5) (5) (5)(1) Level percentage of payroll, closed(2) Depending on age, service, and type of employment(3) Net of pension plan investment expense, including inflation(4) Classic: 50-67 and PEPRA: 52-67(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study adopted by the CalPERS Board. (amounts expressed in thousands)
84REQUIRED SUPPLEMENTARY INFORMATION: ELECTRIC
Reporting period 2024 2023 2022 2021 2020 2019 2018Measurement period 2023 2022 2021 2020 2019 2018 2017Electric Utility's Proportion of the Net OPEB Liability 18.68% 21.63% 24.45% 21.28% 21.41% 22.36% 22.52%Electric Utility's Proportionate Share of the Net OPEB Liability 10,446$ 9,837$ 10,460$ 11,126$ 10,708$ 8,572$ 8,283$ Electric Utility's Covered Payroll 39,099$ 43,955$ 48,238$ 40,761$ 39,816$ 38,204$ 38,477$ Electric Utility's Proportionate Share of the Net OPEB Liability as a Percentage of Covered Payroll 26.72% 22.38% 21.68% 27.30% 26.89% 22.44% 21.53%(1) Historical information is required only for the measurement periods for which GASB 75 is applicable. Fiscal Year 2018 was the first year of implementation. Future years' information will be displayed up to 10 years as information becomes available.Notes to Schedule:Changes in assumptions: For the measurement period ending June 30, 2023, the discount rate was changed from 3.54 percent to 3.65 percent. There are noasset accumulated in a trust that meets the criteria of GASB codification P22.101 or P52.101 to pay related benefits for the OPEB plan.

ELECTRIC UTILITYSCHEDULE OF CHANGES IN TOTAL OPEB LIABILITY AND RELATED RATIOS(amounts expressed in thousands)AS OF JUNE 30, FOR THE LAST SEVEN FISCAL YEARS (1) 85REQUIRED SUPPLEMENTARY INFORMATION: ELECTRIC85
ELECTRIC UTILITY:KEY HISTORICAL OPERATING DATAFiscal Year2023/242022/232021/222020/212019/20POWER SUPPLY MEGAWATT-HOURS (MWH)NuclearPalo Verde103,000101,500101,10099,800100,900CoalIntermountain Power293,600460,400453,900539,200551,300Hoover (Hydro)23,60022,90028,00030,60027,000GasSprings1,0001,4006001,800700RERC54,10076,00054,40083,80068,200Clearwater13,20015,20013,0009,8008,600Renewable resources923,000937,500978,700938,100889,000Market purchases786,800625,000653,200559,200592,300Total2,198,3002,239,9002,282,9002,262,3002,238,000System peak megawatt (MW) 589.8647.8575.9630.3587.2ELECTRIC USENumber of meters as of year endResidential100,505100,05499,73199,22698,930Commercial3 12,24512,02611,92211,81711,598Industrial3 637622625616581Other4949505252Total113,436112,751112,328111,711111,161Millions of kilowatt-hours (kWh) salesResidential710786759783723Commercial3 427440443430442Industrial3 916920923891931Other1215191818Subtotal2,0652,1612,1442,1222,114Wholesale2 -142-1Total2,0652,1752,1462,1222,115ELECTRIC FACTSAverage annual kWhper residential customer7,0747,8737,6327,9077,322Average price (cents/kWh)per residential customer$19.58$17.88$17.71$17.03$16.77Debt service coverage ratio (DSC)4,5,6,72.312.012.031.992.62Operating income as a percentof operating revenues%10.8%10.0%18.6%9.6%12.1Employees1 4734734734684661Approved positions.2For fiscal years 20/21 and 23/24, wholesale kWh was less than 1 million kWh. Increase in fiscal year 22/23 was due to a transmission constraint requiring the power theElectric Utility was scheduled to receive to be resold.3Changes in fiscal years 19/20 and 20/21 reflect reclassification of certain Industrial and Commercial accounts related to contract accounts.4Interest expense used to calculate DSC is net of federal subsidy on Build America Bonds.5Does not include GASB 68 - Accounting and Financial Reporting for Pension non-cash adjustments of $7,707, ($1,308), ($16,425), $9,682, and $3,364 for fiscal years 23/24through 19/20, respectively.6Does not include GASB 75 - Accounting and Financial Reporting for Post-employment Benefits Other than Pensions non-cash adjustments of $474, $431, $530, $183, and$490 for fiscal years 23/24 through 19/20, respectively.7Includes GASB 87 Leases net revenue adjustment of $304, $247 and $134 for fiscal years 23/24 through 21/22, respectively.86KEY HISTORICAL OPERATING DATA: ELECTRIC

Residential Sales 30¢
Industrial Sales 29¢
Commercial Sales 17¢
Transmission Revenue 9¢
Other Revenue 8¢
Investment Income 4¢
Public Benefit Programs 2¢
Other Sales 1¢
Production 44¢
Distribution 16¢
Transmission 12¢
Debt Service 10¢
Transfers to the City's General Fund* 10¢
Additional Reserves 4¢
Additions & Replacements to the System 2¢
Public Benefit Programs 2¢
Renewables 46%
Market Purchases 28%
Coal 16%
Nuclear 5%
Gas 4%
Hydropower 1%
$0$50$100$150$200$250$300*Based on transfer of 11.5% of fiscal year 2022/2023 gross operating revenues including adjustments. **Energy Resources are based on calendar year 2023 as filed with the California Energy Commission 87KEY HISTORICAL OPERATING DATA: ELECTRIC87
$39.6$39.9$39.4$42.3$45.320202021202220232024General Fund Transfer (In Millions)1 111,161111,711112,328112,751113,43620202021202220232024Number of Meters At Year End$367.1$372.1$398.6$418.9$427.420202021202220232024Total Operating Revenue (In Millions)2,2382,2622,2832,2402,19820202021202220232024Production (In Million Kilowatt-Hours)587.2630.3575.9647.8589.820202021202220232024Peak Day Demand (In Megawatts)88KEY HISTORICAL OPERATING DATA: ELECTRIC ELECTRIC FACTS AND SYSTEM DATAEstablished................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................1895Service Area Population................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................316,690City Area Size (square miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................81.5System DataTransmission Lines (circuit miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................99.2Distribution Lines (circuit miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................1,358Number of Substations................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................162023-24 Peak Day (megawatts)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................590Highest Single Hourly Use:08/29/2023, 5pm, 99.9 degreesHistorical Peak (megawatts)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................648Highest Single Hourly Use:09/07/2022, 4pm, 99.3 degreesBond RatingsFitch Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA-S & P Global Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA- 89KEY HISTORICAL OPERATING DATA: ELECTRIC89

R I V E R S I D E P U B L I C U T I L I T I E S

CliftonLarsonAllen LLPCLAconnect.comINDEPENDENT AUDIT REPORT Honorable Mayor City of Riverside Riverside, California Report on the Audit of the Financial Statements Opinion We have audited the accompanying financial statements of the Water Utility Enterprise Fund (Water Utility) of the City of Riverside, as of and for the year ended June 30, 2024, and the related notes to the financial statements, as listed in the table of contents. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Water Fund of the City of Riverside, as of June 30, 2024, and the changes in its financial position, and, its cash flows thereof for the year then ended in accordance with accounting principles generally accepted in the United States of America. Basis for Opinion We conducted our audit in accordance with auditing standards generally accepted in the United States of America (GAAS) and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Our responsibilities under those standards are further described in the Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Water Fund of the City of Riverside and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Emphasis of Matters The financial statements of the Water Utility as of June 30, 2023, were audited by other auditors whose report dated November 8, 2023, expressed an unmodified opinion on those financial statements. As more fully described in Note 12 to the financial statements, the Water Utility has adjusted its 2023 financial statements to reflect a restatement. The other auditors reported on the financial statements before the restatement. As part of our audit of the 2024 financial statements, we also audited the adjustments to the 2023 financial statements to apply the restatement as described in Note 12. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to Water Utfinancial statements other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2023 financial statements as a whole. CLA (CliftonLarsonAllen LLP) is an independent network member of CLA Global. SeeCLAglobal.com/disclaimer.93 Honorable Mayor and Members of the City Council City of Riverside As discussed in Note 1, the financial statements present only the Water Utility and do not purport to, and do not present fairly the financial position of the City of Riverside, California, as of June 30, 2024, the changes in its financial position, or, where applicable, its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America. Our opinion is not modified with respect to this matter. Responsibilities of Management for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS and Government Auditing Standards will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements. In performing an audit in accordance with GAAS and Government Auditing Standards, we: Exercise professional judgment and maintain professional skepticism throughout the audit. Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the WAccordingly, no such opinion is expressed. Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements. We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control related matters that we identified during the audit.

Honorable Mayor and Members of the City Council City of Riverside Required Supplementary Information Accounting principles generally accepted in the United States of America require that the discussion and analysis, the schedule of proportionate share of the net pension liability, the schedule of contributions of the defined benefit plans, and the schedule of the Water proportionate share of of pla be presented to supplement the basic financial statements. Such information is the responsibility of management and, although not a part of the basic financial statements, is required by the Governmental Accounting Standards who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with GAAS, which consisted of inquiries of management about the methods of preparing the information and comparing the information inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance. Other Information Management is responsible for the other information included in the annual report. other information comprises the introductory section and operating statistical section but does not include the basic financial statements and our report thereon. opinion on the basic financial statements do not cover the other information, and we do not express an opinion or any form of assurance thereon. In connection with our audit of the basic financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the basic financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report. Other Reporting Required by Government Auditing Standards In accordance with Government Auditing Standards, we have also issued our report dated December 16, 2024, on our consideration of the City of internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. purpose of that report is solely to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the effectiveness of the City of internal control over financial reporting or on compliance. at report is an integral part of an audit performed in accordance with Government Auditing Standards in considering City of Riinternal control over financial reporting and compliance.

CliftonLarsonAllen LLP Irvine, California December 16, 2024 95 WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISAs management of Riverside Public Utilities, a department of the City of Riverside (the City), we offer the readers thisnarrative overview and analysis of the 2023-24 financial report for the periods ended June 30, 2024 and 2023 forRiverside’s Water Utility (Water Utility), an enterprise fund of the City. We encourage readers to consider the informationpresented here in conjunction with additional information furnished in our financial statements, which begin on page 107 ofthis report. All amounts, unless otherwise indicated, are expressed in thousands of dollars.FINANCIAL HIGHLIGHTSGASB Statement No. 100, Accounting Changes and Error Corrections - This Statement defines accounting changesas changes in accounting principles, changes in accounting estimates, and changes to or within the financial reportingentity and describes the transactions or other events that constitute those changes. It prescribes the accounting andfinancial reporting for (1) each type of accounting change and (2) error corrections, and requires that (a) changes inaccounting principles and error corrections be reported retroactively by restating prior periods, (b) changes to or withinthe financial reporting entity be reported by adjusting beginning balances of the current period, and (c) changes inaccounting estimates be reported prospectively by recognizing the change in the current period. This GASB resulted inprior period adjustments and restatements within the Water Utility's Condensed Statements of Net Position andChanges in Net Position. A prior period adjustment was made to reflect changes to two GASB 87 related leases. Inaddition, restatements were made in revenue related to a capital contribution and capital asset received in fiscal yearended June 30, 2023. Refer to Note 12 for current year adjustments related to GASB Statement No. 100.Governmental Accounting Standards Board No. 96, Subscription-Based Information Technology Agreements (GASB96) - For the year ended June 30, 2023, the financial statements include the adoption of GASB Statement No. 96,Subscription-Based Information Technology Agreements (SBITA). This Statement defines SBITA as a contract thatconveys control of the right to use another party’s information technology software, alone or in a combination withtangible capital asset, as specified in a contract for a period of time in an exchange or exchange-like transaction. Foradditional information, refer to Notes 1, 3, and 11. In December 2022, the 2022 Water Revenue bonds with $58,025 principal were issued to fund short-term and long-term capital projects. For additional information, refer to Note 4. Retail sales, net of uncollectibles/recovery, were $72,929 and $69,854 for the fiscal years ended June 30, 2024 and2023, respectively. The increase in sales was primarily due to a rate plan increase, offset by a decrease inconsumption.Total revenue includes the accounting standard for fair market value adjustment of investments, which will continue tofluctuate based on market valuations. The adjustment was $1,115 and $(536) in June 30, 2024 and 2023,respectively.Operating expense reflects a non-cash pension accounting standard adjustment, which will continue to fluctuate basedon yearly actuarial information provided by the California Public Employees' Retirement System (CalPERS). Theadjustment was $2,483 and $(471) in June 30, 2024 and 2023, respectively.MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISOVERVIEW OF THE FINANCIAL STATEMENTSThis discussion and analysis is intended to serve as an introduction to the Water Utility’s financial statements. The WaterUtility is a department of the City, and its activities are recorded in a separate enterprise fund. These financial statementsinclude only the activities for the Water Utility and provide comparative information for the last two fiscal years. Informationon city-wide financial results is available in the City’s Annual Comprehensive Financial Report (ACFR).The Water Utility’s financial statements are comprised of two components: 1) financial statements and 2) notes to thefinancial statements. In addition, this report also contains other supplementary information to provide the reader withadditional information about the Water Utility, including pension and other postemployment benefit plan information,statistical data, historical sales and operating activities, and other relevant information.Included as part of the financial statements are three separate statements, which collectively provide an indication of theWater Utility’s financial health.The present information on all of the Water Utility’s assets, liabilities, deferred inflows andoutflows of resources and net position. The Statements of Net Position provide information about the nature and amount ofthe Water Utility’s resources and obligations at a specific point in time.The report all of the Water Utility’s revenues andexpenses for the periods shown.The report the cash provided and used by operating activities, as well as other cash sources,such as investment income and debt financing. They also report other cash uses such as payments for bond principal andcapital additions and improvements.The provide additional information that is essential to a full understanding of the dataprovided in the Water Utility's financial statements. The Notes to the Financial Statements begin on page 112 of this 94MANAGEMENT’S DISCUSSION & ANALYSIS: WATER97
WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISWATER UTILITY FINANCIAL ANALYSISCONDENSED STATEMENTS OF NET POSITION202420232022Current and other assets$208,821$219,843$174,574Capital assets534,491517,482508,310Deferred outflows of resources15,23016,9909,647Total assets and deferred outflows of resources758,542754,315692,531Long-term debt outstanding266,133277,159239,544Other liabilities49,23442,86532,469Deferred inflows of resources103,504104,26298,214Total liabilities and deferred inflows of resources418,871424,286370,227Net investment in capital assets304,423298,880293,641Restricted14,80412,47810,988Unrestricted20,44418,67117,675Total net position$339,671$330,029$322,304ASSETS AND DEFERRED OUTFLOWS OF RESOURCES2024 compared to 2023 The Water Utility’s total assets and deferred outflows of resources were $758,542, reflecting anincrease of $4,227 (0.6%), primarily due to the following:Current and other assets, comprised of restricted and unrestricted assets, had a net decrease of $11,022, primarilydue to a decrease of $20,917 in restricted cash and cash equivalents at fiscal agent for the funding of capital projects.The decrease was offset by an increase of $4,258 in unrestricted cash and cash equivalents due to positive operatingresults, as well as an increase of $1,549 in leases receivable.Capital assets increased by $17,009 as a result of an increase in additions and improvements to the Water distributioninfrastructure system to improve service and reliability to Water Utility's customers, offset by an increase in currentyears depreciation. Additional capital asset information can be found in the “Capital Assets and Debt Administration”section.Deferred outflows of resources decreased by $1,760, primarily due to a decrease of $1,450 in deferred outflowsrelated to pension as a result of pension accounting standards, as well as a decrease of $276 in loss on refunding dueto the amortization.2023 compared to 2022 Total assets and deferred outflows of resources were $754,315, reflecting an increase of$61,784 (8.9%), primarily due to the following: Current and other assets, comprised of restricted and unrestricted assets, had a net increase of $45,269, primarily dueto an increase of $52,198 in restricted cash and cash equivalents related to the issuance of the 2022 Water RevenueBonds Series A. The increase was offset by a decrease of $8,809 in net pension asset as a result of pensionaccounting standards.Capital assets increased by $9,172 as a result of an increase in additions and improvements to the Water distributioninfrastructure system to improve service and reliability to Water Utility's customers, offset by an increase in currentyears depreciation. Additional capital asset information can be found in the “Capital Assets and Debt Administration”section.Deferred outflows of resources increased by $7,343, primarily due to an increase of $8,508 in deferred outflowsrelated to pension as a result of pension accounting standards. The increase is offset by a decrease of $812 in the fairvalue of derivatives and a decrease of $270 in loss on refunding due to the amortization.95MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISLIABILITIES AND DEFERRED INFLOWS OF RESOURCES2024 compared to 2023 The Water Utility’s total liabilities and deferred inflows of resources were $418,871, a decrease of$5,415 ((1.3)%), primarily due to the following: Long-term debt outstanding decreased by $11,026, primarily due to principal payments on revenue bonds, pensionobligation bonds and financed purchases. Additional debt information can be found in the “Capital Assets and DebtAdministration” section.Other liabilities increased by $6,369, primarily due to an increase of $4,226 in accounts payable and an increase of$1,601 in net pension liability. Deferred inflows of resources decreased by $758, primarily due to a decrease of $569 in pension-related adjustments,which included the changes in assumptions, the differences between expected and actual experience and the changein projected versus actual earnings on pension plan investments as determined by the plan actuary. There was also adecrease of $493 related to GASB 87 lease adjustments. The decrease was offset by an increase of $387 related toGASB 72 fair value adjustments.2023 compared to 2022 Total liabilities and deferred inflows of resources were $424,286, reflecting an increase of$54,059 (14.6%). Long-term debt outstanding increased by $37,615, primarily due to the issuance of the 2022 Water Revenue BondsSeries A. Additional debt information can be found in the “Capital Assets and Debt Administration” section. Other liabilities increased by $10,396, primarily due to an increase of $12,854 in net pension liability and an increase of$600 in accrued interest payable. The increase was offset by a decrease of $1,269 in derivative instruments due to adecrease in the fair value of interest rate swaps, and a decrease of $1,093 in unearned revenues. Deferred inflows of resources increased by $6,048, primarily due to an increase of $19,152 related to GASB 87 leaseadjustments. The increase was offset by a decrease of $13,627 in pension-related adjustments, which included thechanges in assumptions, the differences between expected and actual experience and the change in projected versusactual earnings on pension plan investments as determined by the plan actuary.NET POSITION2024 compared to 2023 The Water Utility’s total net position, which represents the difference between the Water Utility’stotal assets and deferred outflows of resources less total liabilities and deferred inflows of resources, totaled $339,671, anincrease of $9,642 (2.9%).The largest portion of the Water Utility’s total net position, which is its investment in capital assets of $304,423(89.6%), had an increase of $5,543 from prior year. Investment in capital assets reflects the Water Utility’s investmentin source of supply, pumping and transmission and distribution facilities, less any related outstanding debt used toacquire these assets (net investment in capital assets). Additional capital asset information can be found in the“Capital Assets and Debt Administration” section.The restricted portion of net position totaled $14,804 (4.4%), reflecting an increase of $2,326 and representingresources that are subject to external restrictions on how they may be used. The increase was primarily due to anincrease of $1,157 in the unfunded accrued liability for employee retirement plan, as well as an increase in therestricted debt service reserve. Restricted net position is reserved for items such as debt repayment and fundscollected for Water Conservation Programs, and other legally restricted assets.The unrestricted portion of net position totaled $20,444 (6.0%), reflecting an increase of $1,773 from prior year,primarily attributable to positive operating results and an increase in investment income. Unrestricted net position maybe used to meet the Water Utility’s ongoing operational needs and obligations to customers and creditors. 96MANAGEMENT’S DISCUSSION & ANALYSIS: WATER99 WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSIS2023 compared to 2022 Total net position increased by$7,725 (2.4%), to $330,029, primarily due to the following:The largest portion of the Water Utility’s total net position, which is its investment in capital assets of $298,880(90.5%), had an increase of $5,239 from prior year. Investment in capital assets reflects the Water Utility’s investmentin source of supply, pumping, treatment, and transmission and distribution facilities, less any related outstanding debtused to acquire these assets (net investment in capital assets). Additional capital asset information can be found in the“Capital Assets and Debt Administration” section.The restricted portion of net position totaled $12,478 (3.8%), reflecting an increase of $1,490 and representingresources that are subject to external restrictions on how they may be used. The increase was primarily due to anincrease in restricted debt service reserve related to the issuance of the 2022 Water Revenue Bonds Series A.Restricted net position is reserved for items such as debt repayment and funds collected for Water ConservationPrograms, and other legally restricted assets.The unrestricted portion of net position totaled $18,671 (5.7%), reflecting an increase of $996 from prior year, primarilyattributable to positive operating results and an increase in investment income. Unrestricted net position may be usedto meet the Water Utility’s ongoing operational needs and obligations to customers and creditors.CONDENSED STATEMENTS OF CHANGES IN NET POSITION202420232022Revenues:Retail sales, net$72,929$69,854$72,452Other revenues11,56012,29712,336Investment (loss) income7,0173,67961Capital contributions6,5328,2905,693Total revenues98,03894,12090,542Expenses:Operations and maintenance44,88242,73836,366Purchased energy7,2506,6326,863Depreciation16,75316,36716,179Amortization152011Interest expense and fiscal charges11,3889,9539,471Total expenses80,28875,71068,890Transfers:Transfers to the City's general fund(8,108)(8,170)(7,708)Total Transfers(8,108)(8,170)(7,708)Changes in net position9,64210,24013,944Net position, July 1330,029322,304308,360Error correction-(2,515)-Net position, July 1, as restated330,029319,789308,360Net position, June 30$339,671$330,029$322,30497MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISREVENUES BY SOURCES

2024 compared to 2023The Water Utility’s total revenues of $98,038increased by $3,918 (4.2%), primarily due to thefollowing changes:Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $72,929, anincrease of $3,075 (4.4%) from prior fiscal year. Retail sales continue to be the primary revenue source for the WaterUtility. The increase was due to a rate plan increase, offset by a 1.3% decrease in consumption.Other revenues of $11,560 decreased by $737 (6.0%), primarily due to a decrease of $704 in wholesale water salescompared to prior year.Capital contribution of $6,532 decreased by $1,758 (21.2%), primarily due to a decrease of $1,317 in contribution inaid.Investment income of $7,017 increased by $3,338 (90.7%), primarily due to a fair value adjustment of investments,additional interest earned on the 2022 Water Revenue bonds and a higher overall interest rate in the current fiscalyear.2023 compared to 2022 The Water Utility’s total revenues of $94,120increased by $3,578 (4.0%), primarily due to thefollowing changes:Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $69,854, adecrease of $2,598 (3.6%) from prior fiscal year. Retail sales continue to be the primary revenue source for the WaterUtility. The decrease was due to a 13.7% decrease in consumption.Other revenues of $12,297 decreased by $39 (0.3%), which is consistent with prior year.Capital contribution of $8,290 increased by $2,597 (45.6%), primarily due to an increase of $2,938 in contribution inaid, offset by a decrease of $273 in revenue from other agencies.Investment income of $3,679 increased by $3,618 (5,931.1%), primarily due to a fair value adjustment of investmentsand a higher overall interest rate in the current fiscal year.98MANAGEMENT’S DISCUSSION & ANALYSIS: WATER101 WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISEXPENSES BY SOURCES

2024 compared to 2023 The Water Utility’s total expenses, excluding general fund transfer, were $80,288, an increase of$4,578 (6.0%). The increase was primarily due to the following:Operations and maintenance expenses of $44,882 increased by $2,144 (5.0%), primarily due to a non-cash pensionadjustment as a result of pension accounting standards.Purchased energy expenses of $7,250 increased by $618 (9.3%) from prior year, primarily due to an increase inelectricity costs.2023 compared to 2022 The Water Utility’s total expenses, excluding general fund transfer, were $75,710, an increase of$6,820 (9.9%). The increase was primarily due to the following:Operations and maintenance expenses of $42,738 increased by $6,372 (17.5%), primarily due to an increase inpersonnel-related costs resulting from the elimination of the prior year net pension asset and generation of a netpension liability in fiscal year 2022-23, along with increases in administration and general operating expenses.Purchased energy expenses of $6,632 decreased by $231 (3.4%) from prior year, primarily due to a decrease inelectricity costs.TRANSFERSPursuant to the City's Charter and the voter approval of Measure A on June 4, 2013, the Water Utility may transfer up to11.5 percent of prior year’s gross operating revenues, including adjustments, to the City’s general fund. The City usesthese funds to help provide needed public services to the residents of the City, including police, fire, parks, libraries andother benefits. The Water Utility transferred $8,108 and $8,170 for 2024 and 2023, respectively, based on the grossoperating revenue provisions in the City’s Charter. For additional information, refer to Note 10.99MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISCAPITAL ASSETS AND DEBT ADMINISTRATIONCAPITAL ASSETSThe Water Utility’s investment in capital assets includes investments in source of supply, pumping, treatment, transmissionand distribution facilities, land, intangibles, construction in progress, and lease and subscription assets as well as generalitems such as office equipment, furniture, etc.The following table summarizes the Water Utility’s capital assets, net of accumulated depreciation, as of June 30:20242023*2022Utility plantSource of supply$55,347$54,223$55,231Pumping26,25923,44519,445Treatment24,36225,65225,868Transmission and distribution337,955335,719333,483General4,8074,6364,514Land20,87020,84120,841Intangibles10,85310,88311,005Construction in progress54,01042,05537,907Total utility plant534,463517,454508,294Lease and subscription assetsMachinery and equipment201116Subscription-based information technology arrangements817-Total capital assets$534,491$517,482$508,310* As restated.2024 compared to 2023The Water Utility’s capital assets, net of accumulated depreciation, was $534,491, an increase of$17,009 (3.3%) from prior year. The increase resulted primarily from an increase in construction in progress. The WaterUtility's significant capital projects include the following:$10,564 in water supply facilities, such as Seven Oaks Dam conservation and recycled water facilities.$10,086 in distribution pipelines, such as main replacements, distribution system facilities replacement and systemexpansion. $5,044 in transmission pipelines, such as transmission mains.$2,362 in well projects, such as potable irrigation well replacements and facility rehabilitation. $1,226 in distribution facilities, such as pump station replacements and meters.2023 compared to 2022 The Water Utility's capital assets, net of accumulated depreciation, was $517,482, an increase of$9,172 (1.8%) from prior year. The increase resulted primarily from an increase in construction in progress. The significantcapital projects included the following:$7,919 in distribution pipelines, such as main replacements, distribution system facilities replacement and systemexpansion.$3,323 in well projects, such as potable irrigation well replacements and facility rehabilitation.$2,635 in water supply facilities, such as Seven Oaks Dam conservation and recycled water facilities.$2,334 in transmission pipelines, such as transmission mains.$2,056 in distribution facilities, such as pump station replacements and meters.Additional information regarding capital assets can be found in Note 3 of the accompanying financial statements.100MANAGEMENT’S DISCUSSION & ANALYSIS: WATER103 WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISDEBT ADMINISTRATIONThe following table summarizes outstanding long-term debt as of June 30:202420232022Revenue bonds$235,350$243,300$192,190Unamortized bond premium20,81521,99417,472Arbitrage liability673--Pension obligation bonds18,28419,92421,287Contracts payable931933933Financed purchases7489851,218Note payable--16,639Less: Current portion of outstanding debt(10,668)(9,977)(10,195)Total$266,133$277,159$239,544The Water Utility’s bond indentures require a minimum debt service coverage ratio, as defined by the bond covenants, of1.25. The Water Utility’s debt service coverage ratio was 1.98, 1.95, and 2.23 at June 30, 2024, 2023, and 2022,respectively. The debt is backed by the revenues of the Water Utility. Debt service coverage ratio increased at June 30,2024 due to an increase in net revenues compared to prior year, offset by increases in operating expenses as well asprincipal and interest payments on debt service. For additional information, see Note 4 of the accompanying financialstatements and the Key Historical Operating Data section.2024 compared to 2023 The Water Utility’s long-term debt decreased by $11,026 (4.0%) to $266,133 as a result ofcurrent year principal payments and amortization of bond premiums, offset by an increase in arbitrage liability. 2023 compared to 2022 The Water Utility’s long-term debt increased by $37,615 (15.7%) to $277,159 as a result of theissuance of the 2022 Water Revenue Bonds Series A, offset by current year principal payments and amortization of bondpremiums. Additional information on the Water Utility’s long-term debt can be found in Note 4 of the accompanying financialstatements.CREDIT RATINGS The Water Utility maintains credit ratings of “AA+”, “AA+” and “Aa2” from S&P Global Ratings (S&P), Fitch Ratings (Fitch)and Moody’s, respectively. These ratings reflect the Water Utility’s strong financial performance, advantageous watersupply, investments in infrastructure and rate competitiveness, among many other factors.101MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISREGULATORY, LEGISLATIVE FACTORS, AND RATES Utilities are faced with ongoing regulatory and legislative mandates enacted at the federal and state level that will havesignificant impacts on the operations of the Water Utility. The State of California has experienced unprecedented drought conditions in recent years resulting in severe impacts toCalifornia’s water supplies and its ability to meet all of the demands for water in the State. The Water Utility is veryfortunate as a water provider in California in that the Water Utility owns, operates and maintains its own water supply andis not typically dependent on imported water from outside sources. The Water Utility currently has sufficient water suppliesto meet customer needs even during severe drought conditions; however, the aquifers the Water Utility draws from areexperiencing historic low levels. The Water Utility has responded by continuing to offer a wide variety of water conservationprograms for its customers in an effort to conserve its water resources. The Water Utility continues to offer customers a wide variety of water conservation programs that help reduce their waterusage and utility costs, and help the City meet State mandates and be more sustainable. These programs provide rebatesfor residents and businesses to help them save money by conserving water. In an effort to streamline and automate therebate process, the City formed a partnership with Metropolitan Water District of Southern California to administer andprocess rebates for high-efficiency toilets, clothes washers, irrigation controllers and many other water-saving devices. To further provide comprehensive resources and guidance as to how to implement water efficiency practices at residencesand businesses, the Water Utility, in partnership with the City created the Street Park Turf Conversion and DemonstrationGarden at the Janet Goeske Center. The Demonstration Garden allows residents and businesses to interact with waterconservation materials and techniques that conserve water, elevate customer awareness, increase incentive programparticipation, provide educational opportunities and demonstrate water conservation best practices. The Water Utility’s long-range water supply planning includes significant contributions of conservation, water loss reductionand investments in projects to augment water supply portfolio, such as recycled water and Groundwater Basin recharge.The behavioral changes instituted through conservation and water use efficiency should have some permanent impact.Changes in landscape patterns and uses will have permanent and on-going impacts to water use. Continuing conservationmeasures could negatively impact the Water Utility revenues and has been addressed in the recent cost of serviceanalysis conducted by the Water Utility.During fiscal year 2023/24, RPU’s water use efficiency programs have supported residents and business to save nearly 11million gallons of water. These savings are the result of the range of RPU’s incentivization programs, which include high-efficiency clothes washers, toilets and weather-based irrigation controllers and the Smart Irrigation Program (SIP). WATER CONSERVATIONOn November 10, 2009, the Governor signed SBX7-7, which focused on reducing urban (municipal) water use, mainlythrough reductions in residential potable water use, throughout California. The Water Utility’s 2015 Urban WaterManagement Plan (UWMP) reported its Baseline Water Use and calculated its 2020 Urban Water Use Target. In its 2020UWMP, the Water Utility demonstrated its compliance with SB X7-7 by showing actual 2020 water use below its 2020Urban Water Use Target. On May 31, 2018, Governor Jerry Brown signed long-term water-use efficiency bills Senate Bill 606 and Assembly Bill1668 into law to establish a long-term foundation for water use efficiency and drought planning.Under AB 1668, the City must set, meet and report water use objectives for its service area using a water budget-basedapproach by 2025. In total, four water use standards including indoor residential use, outdoor residential use, commercial,industrial, and institutional dedicated irrigation meter use, and water loss will be aggregated to calculate a water purveyor'sunique efficient water use target. Final regulations were adopted in July 2024, with reporting beginning 2025. In addition,under SB 606, the City must conduct and submit an Annual Water Supply and Demand Assessment report starting in2022 and a Drought Risk Assessment every 5 years as part of its Urban Water Management Plan.102MANAGEMENT’S DISCUSSION & ANALYSIS: WATER105 WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISAB 1572 prohibits the use of potable water, as defined, for the irrigation of nonfunctional turf located on commercial,industrial, institutional, and multifamily residential properties, as specified. The bill would require the State WaterResources Control Board to establish, no later than July 1, 2025, specified compliance and certification requirements. Thebill would require owners of covered properties to certify their compliance with these provisions, as specified.The "Making Conservation a California Way of Life" regulation aims to establish a regulatory framework for achieving long-term water use efficiency and address the challenges posed by climate change and the increasing frequency and severityof droughts in California. Under the new regulations, around 400 urban water suppliers will need to meet individualizedwater-use targets, among other performance standards and reporting requirements.This new framework represents a departure from the previous one-size-fits-all approach to water management inCalifornia, such as the mandatory 25% statewide water reductions ordered by Governor Jerry Brown during the 2012-2016drought. The new regulation allows suppliers to consider local factors like climate, population, and landscaped areas; andwere collaboratively developed with stakeholder input over the past 6 years. This regulation also promises to lessen theneed for enacting emergency water use reductions during drought episodes.On July 3, 2024, the SWRCB adopted the regulation titled “Making Conservation a California Way of Life.” This regulationis designed to promote long-term water use efficiency in response to California's changing climate and the growingfrequency and severity of droughts.Under the regulation, urban retail water suppliers must comply with four major components: A supplier-specific Urban Water Use Objective,Commercial, Industrial, and Institutional (CII) performance measures,Water Loss Performance Standard,and Annual reporting.The City of Riverside has been engaged with the development of the regulation since it was signed into law in 2018,participating in workshops, attending public hearings, and submitting formal comment letters during the rulemakingprocess. In preparation, the City has also calculated multiple compliance scenarios using conservative estimates toassess the City’s performance for each of the Objective standards as they become more stringent through 2040.Staff anticipates being in compliance with the overall Objective until 2035, when the City may exceed its budget between3% to 7% without considering any additional conservation efforts or outreach campaigns. Efforts conducted by the City’sCustomer Engagement division are anticipated to bridge that gap and help the City meet its Objective.Customer Engagement EffortsRPU's Customer Engagement (CE) division assists both residential and commercial customers increase their water useefficiency through a variety of programs, incentives, rebates, and education. The CE team is responsible for severalcritical tasks to help the City comply with the new long-term water use efficiency regulations. These tasks include:Residential Indoor/Outdoor Water Use: CE will continue to utilize existing water use efficiency programs and incentives forcustomers. Additionally, RPU’s long-standing Smart Irrigation Program, focused on inefficient and high-water users, iscurrently under review. CE has also secured a two-year contract at no cost for a new water efficiency software calledWaterView. This tool will allow the CE team to support the creation of outreach campaigns to target inefficient water usersand provide customer-appropriate level of assistance, rebates, and incentives. In the future, programs may be expandedincluding potential new direct installation programs for various water saving devices.CII Outdoor Water Use (Dedicated Irrigation Meters): For CII customers with Dedicated Irrigation Meters (DIMs),landscape irrigation water budgets will be generated and compared to actual irrigation water usage, providing tailoredassistance for customers watering more than their landscape needs. The CE team anticipates expanding currentlandscape and irrigation incentive programs, targeting inefficient water users, and may consider offering a LandscapeOptimization Service Program for this customer type.103MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISCII Mixed Use Meters (MUMS): For commercial CII Mixed Use Meters (MUMs) with irrigated landscapes, CustomerEngagement will identify mixed use meters that serve properties with a minimum of 0.5 acres of irrigated area. Per thenew regulations, CE will implement in-lieu technologies, which will work in concert with the required Best ManagementPractices (BMPs). In-lieu technologies include measures, which are currently under consideration, such as hardwareimprovements, remote sensing, and other technologies to help CII customers with MUMs irrigate their landscapes moreefficiently. BMPs include outreach, education, incentives, landscape measures, agency collaboration and operationalenhancements, such as billing and data management.RPU’s Customer Engagement team will also offer customer education and outreach to support the City’s compliance withthe new regulation. RPU will maintain its commitment to customer education through enhanced community engagementand expanded educational opportunities for local students.WATER STANDARDSThe development of new and increasingly stringent drinking water regulations by the California Environmental ProtectionAgency (CalEPA) and the U.S. Environmental Protection Agency (USEPA) are significantly impacting water supply coststhroughout the state and the nation. New chemical and biological contaminants are being discovered through moresophisticated research techniques and improved analytical methods. In addition, public health and environmental agenciesare now evaluating how anthropogenic factors are impacting our water supplies. Pesticides, pharmaceuticals, andpersonal care products are being evaluated at trace levels, which can be orders of magnitude lower than what wasachievable 20 years ago. As a result, water treatment costs are increasing as federal and state legislators and regulatorstry to balance public health risk with affordable water supply costs.On July 21, 2020, the USEPA published a final action to withdraw the Agency’s 2011 regulatory determination to regulateperchlorate after finding that perchlorate did not occur with a frequency and at levels of public health concern within themeaning of the Safe Drinking Water Act, and that development of a regulation did not present a meaningful opportunity forhealth risk reduction for persons served by public water systems. However, the State of California began regulatingperchlorate in 2007 with a MCL set at 6 parts per billion (“ppb”) and a detection level for purposes of reporting (DLR) of 4ppb. Beginning July 1, 2021, the DLR was lowered to 2 ppb and will be lowered to 1 ppb effective January 1, 2024. Afterdata is collected at these lower DLR’s evaluation of the perchlorate MCL, and possible need for reduction, will occur. Areduction in the perchlorate standard could impact the Water Utility’s water supply costs.In December 2016, the USEPA completed its third review of existing National Primary Drinking Water Regulations(NPDWR) (i.e., the Six-Year Review 3). The USEPA determined that 68 of the 76 NPDWR remain appropriate (i.e., do notneed to be revised) and that eight NPDWRs are candidates for regulatory revision. These eight NPDWRs are included inthe Stage 1 and the Stage 2 Disinfectants and Disinfection Byproducts Rules, the Surface Water Treatment Rule, theInterim Enhanced Surface Water Treatment Rule and the Long Term 1 Enhanced Surface Water Treatment Rule. Theeight NPDWRs are chlorite, Cryptosporidium, Giardia lamblia, haloacetic acids (HAA5), heterotrophic bacteria, Legionella,total trihalomethanes (TTHM) and viruses. Any revision resulting in the lower of these standards may impact the WaterUtility’s water supply costs. In June 2020, the USEPA began collecting contaminant occurrence data and treatmenttechnique information for its fourth, six-year review which is anticipated to be completed in 2023.On December 14, 2017, the State Water Resources Control Board (SWRCB) adopted an MCL for 1,2,3-Trichloropropane(“1,2,3-TCP) of 0.000005 mg/L or 5 parts per trillion (ppt). Water Quality Monitoring was initiated in 2018. To date, seven ofthe City’s potable wells show detections of 1,2,3-TCP that exceed the MCL. These wells extract water from the sameaquifers that are contaminated by other known anthropogenic chemicals and are currently being treated by existing GACtreatment facilities.Perfluorooctanoic acid (PFOA) and perfluorooctane sulfonic acid (PFOS) are fluorinated organic chemicals which are partof a family of compounds referred to as per- and polyfluoroalkyl substances (PFAS). PFAS are synthetic compounds thatare water and lipid resistant and are useful for a variety of manufacturing processes and industrial applications. In May2016, the USEPA issued a lifetime health advisory for PFOA and PFOS in drinking water of a combined level of 70 ppt. InFebruary 2021, the USEPA determined to move forward with the process of implementing a national primary drinkingwater regulation for PFOA and PFOS. In March 2023, the USEPA issued health-based, non-enforceable MaximumContaminant Level Goals and draft MCLs for six PFAS chemicals: PFOA, PFOS, Perfluorohexane sulfonic acid (PFHxS),Perfluorononanoic acid (PFNA), GenX chemicals, and Perfluorobutane sulfonic acid (PFBS). The following MCLs wereadopted on April 10, 2024: PFOA at 4 ppt, PFOS at 4 ppt, and PFNA, PFHxS, PFBS and GenX regulated together as a104MANAGEMENT’S DISCUSSION & ANALYSIS: WATER107 WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISHazard index where the ratio of the chemicals when added together must be less than 1. The Hazard index establishedHealth Based Water Concentrations for PFHxS of 10 ppt, PFNA at 10 ppt, GenX at 10 ppt, and PFBS at 2,000 ppt. Theregulation requires water systems to complete initial monitoring by 2027, and reduce levels over the MCL by 2029. Inaddition, on April 19, 2024, the USEPA designated PFOA and PFOS as hazardous substances under CERCLA whichwould increase transparency and hold polluters accountable however, could also increase disposal costs for spent GAC orIX media used to remove PFAS.With respect to California, in August 2019, the SWRCB-DDW established Notification Levels for PFOA and PFOS of 5.1and 6.5 ppt, respectively, and in February 2020, DDW issued updated drinking water response levels of 10 ppt for PFOAand 40 ppt for PFOS based on a running four-quarter average. On February 6, 2020 the SWRCB tasked OEHHA to setadvisory limits for perfluorohexane sulfonic acid (PFHxS), perfluorobutane sulfonic acid (PFBS), perfluorohexanoic acid(PFHxA), perfluoroheptanoic acid (PFHpA), perfluorononanoic acid (PFNA), perfluorodecanoic acid (PFDA), and 4,8-dioxia-3H-perfluorononanoic acid (ADONA), in addition to PFOS and PFOA. On March 5, 2020 PFBS was issued anotification level of 500 ppt and a response level of 5000 ppt, by the SWRCB. In June 2021, the Office of EnvironmentalHealth Hazard Assessment (OEHHA) released a draft PHG for PFOA and PFOS at 0.007 ppt and 1 ppt respectively.Following OEHHA’s March 2022 recommendations on PFHxS, the SWRCB-DDW issued a Notification Level of 3 ppt anda Response Level of 20 ppt in October of 2023. On September 18, 2024, the OEHHA recommended a NL of 1,000 ppt forPFHxA.The City believes that PFAS have been in the groundwater basins from which the City draws water in very lowconcentrations for many years. Recent technological advances enabled water agencies to detect PFAS compounds atsuch low concentrations. The City’s goal is to remain below the Notification Levels, which are lower than the ResponseLevel. Many of the City’s wells with detections of PFAS also extract water from the same aquifers that are contaminated byother known anthropogenic chemicals and are currently being treated by existing treatment facilities. Beginning fall 2019,the Board approved the expenditure of approximately $850,000 to test new treatment technologies, assess the feasibilityof resurrecting an abandoned treatment plant to treat a well field with high levels of PFAS and develop a long-term watertreatment strategy.The Water Utility will continue to monitor the progress of the proposed standard changes and will advocate for standardsthat protect human health and are based on the best available science.CLEAN WATER ACTIn April 2020, the US EPA and US Army published the Navigable Waters Protection Rule to define “Waters of the UnitedStates.” The published rule streamlined the definition so that it includes four simple categories of jurisdictional waters,provides clear exclusions for many water features that traditionally have not been regulated, and defines terms in theregulatory text that have never been defined before. This definition was different from that of the 2015 Clean Water Rulewhich would have expanded the scope of Federal jurisdiction. However, in June 2021, the USEPA and Department of theArmy announced their intent to initiate a new rulemaking process that restores the protections in place prior to the 2015rule and develops a new rule to establish a durable definition of “Waters of the US” that reflects consideration of priorSupreme Court decisions.On August 29, 2023, the EPA and US Army Corps of Engineers issued a final rule to conform to the key aspects of theSupreme Courts May 2023 decision. The major changes include:Removal of the "Significant Nexus" Test, which was used to determine federal jurisdiction over certain waters based ontheir impact on larger, traditionally navigable waters. Under the new rule, only waters with a "continuous surfaceconnection" to navigable waters fall under federal oversight.Wetlands must now have a direct surface connection to navigable waters to be considered for federal protection. Thisreduces federal oversight over many wetlands and ephemeral streams.Consequently, regulatory responsibility for waters and wetlands no longer under federal protection might shift to state andlocal authorities.105MANAGEMENT’S DISCUSSION & ANALYSIS: WATER WATER UTILITY:MANAGEMENT'S DISCUSSION AND ANALYSISFIVE-YEAR WATER RATE PLANOn September 19, 2023, the City Council approved a five-year Water Rate Plan, which includes system average annualrate increases. The first annual rate increase was effective October 1, 2023, with the following four years effective on July1 of each year. The approved five-year Water Rate Plan includes annual reviews of the adopted rates by City Council.The system average rate increases are 6.5% each year of the five-year Water Rate Plan. The Water Rate Plan wasdesigned to provide financial stability and correct the imbalance of costs versus revenue recovery. REQUESTS FOR INFORMATIONThis financial report is designed to provide a general overview of the Water Utility’s finances. Questions concerning anyinformation provided in this report or requests for additional financial information should be addressed to the UtilitiesAssistant General Manager – Finance and Administration, Riverside Public Utilities, 3750 University Avenue, 5th floor,Riverside, CA 92501. Additional financial information can also be obtained by visiting www.RiversidePublicUtilities.com. 106MANAGEMENT’S DISCUSSION & ANALYSIS: WATER109
WATER UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF NET POSITIONJune 30,2024June 30,2023ASSETS AND DEFERRED OUTFLOWS OF RESOURCES(in thousands)NON-CURRENT ASSETS:Capital assets:Utility plant, net of accumulated depreciation (Note 3) $448,738$443,713Capital assets, not depreciated (Note )85,72573,741Lease and subscription assets, net of amortization (Note 3 & 11) 2828Total capital assets534,491517,482Restricted assets:Cash and cash investments at fiscal agent (Note 2) 1,840-Cash and cash equivalents at fiscal agent (Note 2)34,55555,488Total non-current restricted assets36,39555,488Other non-current assets:Regulatory assets1,3321,404Leases receivable (Note 11) 88,72287,173Total other non-current assets90,05488,577Total non-current assets:660,940661,547CURRENT ASSETS: Unrestricted assets:Cash and cash equivalents (Note 2) 53,44949,191Accounts receivable, less allowance for doubtful accounts2024$660; 2023$93011,86011,019Accrued interest receivable2,9801,981Leases receivable (Note 11) 847763Prepaid expenses218212Total unrestricted current assets69,35463,166Restricted assets: Cash and cash equivalents (Note 2) 9,2468,933Water Conservation Programs - cash and cash equivalents (Note 2)3,7473,545Water Conservation Programs receivable25134Total restricted current assets13,01812,612Total current assets82,37275,778Total assets743,312737,325DEFERRED OUTFLOWS OF RESOURCES: Deferred outflows related to pension (Note 6) 10,13811,588Deferred outflows related to other postemployment benefits (Note 7)610644Loss on refunding4,4824,758Total deferred outflows of resources15,23016,990Total assets and deferred outflows of resources$758,542$754,315See accompanying notes to the financial statements107FINANCIAL STATEMENTS: WATER WATER UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF NET POSITIONJune 30,2024June 30,2023NET POSITION, LIABILITIES AND DEFERRED INFLOWS OF RESOURCES(in thousands)NET POSITION: Net investment in capital assets$304,423$298,880Restricted for:Debt service (Note 8) 9,9288,933Unfunded accrued liability for employee retirement plan (Note 6)1,157-Water Conservation Programs3,7193,545 Unrestricted20,44418,671Total net position339,671330,029LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (Note4)266,133277,159OTHER NON-CURRENT LIABILITIES:Compensated absences (Note 5) 643527Net pension liability (Note 6) 14,45512,854Other postemployment benefits liability (Note 7) 4,1033,872Derivative instruments (Note 4) 8311,377Regulatory liability4,5164,357Lease liability (Note 11) 167SBITA liability (Note 11) -2Total other non-current liabilities24,56422,996CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS: Accrued interest payable2,5122,609Water Conservation Programs payable53135Current portion of long-term obligations (Note 4) 10,5189,827Total current liabilities payable from restricted assets13,08312,571CURRENT LIABILITIES:Accounts payable and other accruals8,1393,913Compensated absences (Note 5) 2,0341,958Customer deposits1,0401,034Unearned revenue5552Other postemployment benefits liability162171Current portion of long-term obligations (Note 4) 150150Lease liability (Note 11) 55SBITA liability (Note 11) 215Total current liabilities11,5877,298Total liabilities315,367320,024DEFERRED INFLOWS OF RESOURCES: Deferred inflows related to pension (Note 6) 6181,187Deferred inflows related to other postemployment benefits (Note 7)806889Changes in derivative values583196Lease related items (Note 11) 101,497101,990Total deferred inflows of resources103,504104,262Total net position, liabilities and deferred inflows of resources$758,542$754,315See accompanying notes to the financial statements108FINANCIAL STATEMENTS: WATER111 WATER UTILITY:FINANCIAL STATEMENTSSTATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITIONFor the Fiscal YearsEnded June 30,20242023(in thousands)OPERATING REVENUES: Residential sales$45,969$44,185Commercial sales24,85823,430Other sales2,2662,268Water conveyance revenue3,6913,381Water Conservation Programs9831,090Other operating revenue3,6594,349Total operating revenues before uncollectibles81,42678,703Estimated uncollectibles, net of bad debt recovery(164)(29)Total operating revenues, net of uncollectibles81,26278,674OPERATING EXPENSES:Operations37,51734,956Maintenance6,5576,805Purchased energy7,2506,632Water conservation808977Depreciation16,75316,367Amortization1520Total operating expenses68,90065,757Operating income12,36212,917NON-OPERATING REVENUES (EXPENSES): Investment (loss) income7,0173,679Interest expense and fiscal charges(11,388)(9,953)Gain on sale of assets(173)119Other3,4003,358Total non-operating revenues (expenses)(1,144)(2,797)Income (loss) before capital contributions and transfers11,21810,120Capital contributions6,5328,290Transfers out - contributions to the City's general fund(8,108)(8,170)Total capital contributions and transfers(1,576)120Change in net position9,64210,240NET POSITION, BEGINNING OF YEAR, AS PREVIOUSLY STATED330,029322,304ERROR CORRECTION (Note 12) -(2,515)NET POSITION, BEGINNING OF THE YEAR, AS RESTATED330,029319,789NET POSITION, END OF YEAR$339,671$330,029See accompanying notes to the financial statements109FINANCIAL STATEMENTS: WATER WATER UTILITY:FINANCIAL STATEMENTSSTATEMENT OF CASH FLOWSFor the Fiscal YearsEnded June 30,202402023(in thousands)CASH FLOWS FROM OPERATING ACTIVITIES: Cash received from customers and users$80,539$79,617Cash paid to suppliers for goods and services(29,278)(31,432)Cash paid to employees for services(15,869)(18,778)Net cash provided (used) by operating activities35,39229,407CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:Transfers out - contributions to the City's general fund(8,108)(8,170)Debt service payment on pension obligation bonds(1,640)(1,363)Other non-operating receipts1,2742,054Net cash provided (used) by non-capital financing activities(8,474)(7,479)CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES: Purchase of utility plant(30,154)(20,181)Proceeds from the sale of utility plant258130Proceeds from revenue bonds, including premium-63,596Bond issuance costs-(582)Principal paid on long-term obligations(8,188)(7,148)Interest paid on long-term obligations(11,646)(10,074)Capital contributions2,4912,932Lease and subscription payments(15)(20)Net cash provided (used) by capital and related financing activities(47,254)28,653CASH FLOWS FROM INVESTING ACTIVITIES:Proceeds from/(purchase of) investment securities(1,840)-Income (loss) from investments6,0161,947Net cash provided (used) by investing activities4,1761,947Net increase (decrease) in cash and cash equivalents(16,160)52,528Cash and cash equivalents, beginning of year (including $67,966 and $15,553 at June 30, 2023 andJune 30, 2022, respectively, reported in restricted accounts)117,15764,629Cash and cash equivalents, end of year (including $47,548 and $67,966 at June 30, 2024and June 30, 2023, respectively, reported in restricted accounts)$100,997$117,157See accompanying notes to the financial statements110FINANCIAL STATEMENTS: WATER113 WATER UTILITY:FINANCIAL STATEMENTSSTATEMENT OF CASH FLOWSFor the Fiscal YearsEnded June 30,202402023(in thousands)RECONCILIATION OF OPERATING INCOME TO NET CASH PROVIDED (USED) BYOPERATING ACTIVITIESOperating income (loss)12,36212,917ADJUSTMENTS TO RECONCILE OPERATING INCOME (LOSS) TO NET CASHPROVIDED (USED) BY OPERATING ACTIVITIES: Depreciation16,75316,367Amortization1520(Increase) decrease in accounts receivable29(146)(Increase) decrease in utility billed receivable(218)1,782(Increase) decrease in utility unbilled receivable(577)243(Increase) decrease in intergovernmental receivable(75)106(Increase) decrease in Water Conservation Programs receivable10938(Increase) decrease in prepaid items(6)(13)Increase (decrease) in accounts payable3,739(928)Increase (decrease) in accrued payroll9628Increase (decrease) in retainage payable391403Increase (decrease) in compensated absences192(88)Increase (decrease) in unearned revenue3(1,093)Increase (decrease) in Water Conservation Programs payable(82)64Increase (decrease) in deposits payable612Changes in net pension liability (asset) and related deferred inflows (outflows) ofresources2,482(472)Changes in OPEB liability and related deferred outflows and inflows of resources173167Net cash provided (used) by operating activities$35,392$29,407SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:Capital contributions - capital assets4,0415,358 See accompanying notes to the financial statements111FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESThe Water Utility exists under, and by virtue of, the City of Riverside (the City) Charter enacted in 1883. The Water Utility isresponsible for the production, transmission and distribution of water for sale in the City, except for certain areas served byanother water utility. The accompanying financial statements present only the financial position and the results ofoperations of the Water Utility, which is an enterprise fund of the City, and are not intended to present fairly the financialposition and results of operations of the City in conformity with generally accepted accounting principles. However, certaindisclosures are for the City as a whole, since such information is generally not available for the Water Utility on a separatefund basis. All amounts, unless otherwise indicated, are expressed in thousands of dollars.BASIS OF ACCOUNTINGThe Water Utility uses the accrual basis of accounting as required for enterprise funds with accounting principles generallyaccepted in the United States of America as applicable to governments. The accounting records of the Water Utility arealso in conformity with the Uniform System of Accounts prescribed by the California Public Utilities Commission. TheWater Utility is not subject to the regulations of the California Public Utilities Commission.The Water Utility distinguishes operating revenues and expenses from non-operating items. Operating revenues andexpenses generally result from providing services and producing and delivering goods in connection with an enterprisefund’s principal ongoing operations. The principal operating revenues of the Water Utility are charges to customers forwater sales and services. Operating expenses for the Water Utility include the cost of water sales and services,administrative expenses, and depreciation on capital assets. All revenues and expenses not meeting this definition arereported as non-operating revenues and expenses.IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENTSThe following new Governmental Accounting Standards Board (GASB) pronouncements were effective and have beenimplemented for fiscal year 2023-2024 audit: GASB Statement No. 99, Omnibus 2022 - This Statement provides clarification on previously issued Statements, includingthe classification and reporting of derivative instruments within the scope of Statement No. 53, Accounting and FinancialReporting for Derivative Instruments, that do not meet the definition of either an investment derivative instrument or ahedging derivative instrument; clarification of provisions in Statement No. 87, Leases, as amended, related to thedetermination of the lease term, classification of a lease as a short-term lease, recognition and measurement of a leaseliability and a lease asset, and identification of lease incentives; clarification of provisions in Statement No. 94, Public-Private and Public-Public Partnerships and Availability Payment Arrangements, related to (a) the determination of thepublic-private and public-public partnership (PPP) term and (b) recognition and measurement of installment payments andthe transfer of the underlying PPP asset; clarification of provisions in Statement No. 96, Subscription-Based InformationTechnology Arrangements, related to the subscription-based information technology arrangement (SBITA) term,classification of a SBITA as a short-term SBITA, and recognition and measurement of a subscription liability; extension ofthe period during which the London Interback Offered Rate (LIBOR) is considered an appropriate benchmark interest ratefor the qualitative evaluation of the effectiveness of an interest rate swap that hedges the interest rate risk of taxable debt;accounting for the distribution of benefits as part of the Supplemental Nutrition Assistance Program (SNAP); disclosuresrelated to nonmonetary transactions; pledges of future revenues when resources are not received by the pledginggovernment; clarification of provisions in Statement No. 34, Basic Financial Statements—and Management's Discussionand Analysis—for State and Local Governments, as amended, related to the focus of the government-wide financialstatements; terminology updates related to certain provisions of Statement No. 63, Financial Reporting of DeferredOutflows of Resources, Deferred Inflows of Resources, and Net Position; and terminology used in Statement 53 to refer toresource flows statements.GASB Statement No. 100, Accounting Changes and Error Corrections - This Statement defines accounting changes aschanges in accounting principles, changes in accounting estimates, and changes to or within the financial reporting entityand describes the transactions or other events that constitute those changes. It prescribes the accounting and financialreporting for (1) each type of accounting change and (2) error corrections, and requires that (a) changes in accountingprinciples and error corrections be reported retroactively by restating prior periods, (b) changes to or within the financialreporting entity be reported by adjusting beginning balances of the current period, and (c) changes in accounting estimatesbe reported prospectively by recognizing the change in the current period. Refer to Note 12 for current year adjustmentsrelated to GASB Statement No. 100.112NOTES TO THE FINANCIAL STATEMENTS: WATER115 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)USE OF ESTIMATESThe preparation of financial statements in conformity with accounting principles generally accepted in the United Statesrequires management to make estimates and assumptions that affect the reported amounts of assets and liabilities andthe reported amounts of revenues and expenses during a reporting period. Accordingly, actual results could differ fromthose estimates.REVENUE RECOGNITIONThe Water Utility customers are billed monthly. Unbilled water service charges, including the Water ConservationPrograms, are recorded at year-end and are included in accounts receivable. Unbilled accounts receivable totaled $3,983at June 30, 2024, and $3,456 at June 30, 2023.An allowance for doubtful accounts is maintained for utility and miscellaneous accounts receivable. The balance in thisaccount is adjusted at fiscal year-end to approximate the amount anticipated to be uncollectible.WATER UTILITY PLANT AND DEPRECIATIONThe Water Utility defines capital assets as assets with an initial, individual cost of more than five thousand dollars and anestimated useful life in excess of one year. Utility plant assets are valued at historical costs or estimated historical cost, ifactual historical cost is not available. Costs include labor; materials; allocated indirect charges such as engineering,supervision, construction and transportation equipment; retirement plan contributions and other fringe benefits. Contributedplant assets are valued at estimated fair value on the date contributed. The cost of relatively minor replacements isincluded in maintenance expense. Intangible assets that cost more than one hundred thousand dollars with useful lives ofat least three years are capitalized and are recorded at cost.Depreciation is recorded over the estimated useful lives of the related assets using the straight-line method. The estimateduseful lives are as follows:Supply, pumping and treatment plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................20-50 yearsTransmission and distribution plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................25-50 yearsGeneral plant and equipment................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-50 yearsIntangibles................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-15 yearsRESTRICTED ASSETSProceeds of revenue bonds yet to be used for capital projects, as well as certain resources set aside for debt service, areclassified as restricted assets on the Statements of Net Position because their use is limited by applicable bond covenants.Proceeds from financed purchase agreements yet to be used for the acquisition of capital equipment are also classified asrestricted assets because their use is legally restricted for a specific purpose. Generally, the Water Utility will first applyrestricted resources when expenses incurred for which both restricted and unrestricted resources are available.In June 2004, the Water Utility began collecting a surcharge for Water Conservation Programs. The surcharge is a 1.5%charge applied to all water customer bills. It has been in place for 20 years and helps fund water conservation programsand customer education. The surcharge can only be used for conservation, education, and water-use efficiency rebateprograms; and research, development, and demonstration programs to advance science and technology with respect towater conservation. On January 22, 2024, the Board conducted a public hearing to receive input on the renewal of theWater Conservation Charge. At the meeting, the last surcharge was adopted on April 22, 2014 and was set to expire onApril 22, 2024. Continued from March 19, 2024, on April 16, 2024, City Council voted to discontinue the WaterConservation Surcharge. The Water Conservation Program will continue until funds are exhausted. The WaterConservation Surcharge expired on April 22, 2024, and has been removed from customer bills.CASH AND CASH EQUIVALENTSFor the Statements of Cash Flows, cash and cash equivalents include all unrestricted and restricted highly liquidinvestments with original purchase maturities of three months or less, and all bond construction proceeds available forcapital projects held at fiscal agent. Pooled cash and investments in the City’s Treasury represent monies in a cashmanagement pool. Such accounts are similar in nature to demand deposits and are classified as cash equivalents for thepurpose of presentation in the Statements of Cash Flows.113NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)CASH AND INVESTMENTSIn accordance with the Water Utility policy, the Water Utility’s cash and investments, except for cash and investments withfiscal agents, are invested in a pool managed by the Treasurer of the City. Cash accounts of all funds are pooled forinvestment purposes to enhance safety and liquidity, while maximizing interest earnings. The Water Utility does not ownspecific, identifiable investments of the pool. The pooled interest earned is allocated monthly based on the month end cashbalances.The Water Utility values its cash and investments in accordance with provisions of GASB Statement No. 72, Fair ValueMeasurement and Application, which requires governmental entities to use valuation techniques that are appropriate underthe circumstances and for which sufficient data are available to measure fair value. The techniques should be consistentwith one or more of the following approaches: the market approach, the cost approach or the income approach. Valuationincludes a hierarchy of inputs with three distinct levels. Level 1 are quoted prices in an active market for identical assets;Level 2 inputs are significant other observable inputs; and Level 3 inputs are significant unobservable inputs. The WaterUtility does not value any of its investments using level 3 inputs.City-wide information concerning cash and investments as of June 30, 2024, including authorized investments, fair valuemeasurement and application, custodial credit risk, credit and interest rate risk for debt securities and concentration ofinvestments, carrying amount and market value of deposits and investments can be found in the notes to the City’sfinancial statements in the City’s Annual Comprehensive Financial Report.CASH AND INVESTMENTS AT FISCAL AGENTSCash and investments maintained by fiscal agents are considered restricted by the Water Utility. Pursuant to certain bondindentures, the fiscal agent establishes, maintains and holds in trust a separate restricted rebatable arbitrage account. TheWater Utility calculates the rebatable arbitrage liability annually and fiscal agent pays the computed arbitrage rebate to theU.S. Treasury every five years. See Note 8 for further discussion related to the arbitrage. CalPERS's positive investment returns contributed to the reduction of the unfunded accrued liability (UAL); as a result,originally budgeted UAL payments were redirected to the Water Utility's restricted cash and investments held at fiscalagent to aid the Water Utility in long-term management of rising pension costs. See Notes 6 for further discussion relatedto the CalPERS pension plan, including UAL.DESIGNATED CASH RESERVESThe Riverside Public Utilities Cash Reserve Policy establishes several designated cash reserves in the Water Utility forstrategic purposes. Designated reserves are set aside for specific purposes determined by the Board of Public Utilities andCity Council. Designated reserves may be held for capital or operating purposes.Designated cash reserve balances as of June 30, 2024 and 2023 were as follows: Property Reserve $6,135 and $5,926,Recycled Water Reserve $778 and $1,013, Customer Deposits $858 and $803, and Capital Repair and ReplacementReserve $2,437 and $2,378, respectively. The combined total for these reserves was $10,208 and $10,120 at June 30,2024 and 2023, respectively, and is included as a component of unrestricted cash and cash equivalents in theaccompanying Statements of Net Position.DERIVATIVESThe Water Utility accounts for derivative instruments using GASB Statement No. 53, Accounting and Financial Reportingfor Derivative Instruments (GASB 53). This Statement requires the Water Utility to report its derivative instruments at fairvalue. Changes in fair value for effective hedges are to be reported as deferred inflows and outflows of resources on theStatements of Net Position. Changes in fair value of derivative instruments not meeting the criteria for an effective hedge,or that are associated with investments are to be reported in the non-operating revenues section of the Statements ofRevenue, Expenses and Changes in Net Position.The Water Utility has determined that its interest rate swaps associated with variable rate obligations are derivativeinstruments under GASB 53. See Note 4 Long-Term Obligations for further discussion related to the Water Utility’s interestrate swaps.114NOTES TO THE FINANCIAL STATEMENTS: WATER117 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)BOND PREMIUMS/DISCOUNTS AND GAINS/LOSSES ON REFUNDINGBond premium/discounts and gains/losses on refunding (including gains/losses related to interest rate swap transactions)are deferred and amortized over the term of the new bonds using the effective interest method. Bonds payable arereported net of the applicable bond premium or discount. Gains/losses on refunding are reported as deferred inflows oroutflows of resources.CUSTOMER DEPOSITSThe City holds customer deposits as security for the payment of utility bills and plan check fee deposits for future waterconnection. The Water Utility’s portion of these deposits as of June 30, 2024 and 2023 was $1,040 and $1,034,respectively.COMPENSATED ABSENCESThe accompanying financial statements include accruals for salaries, fringe benefits and compensated absences due toemployees at June 30, 2024 and 2023. The Water Utility treats compensated absences due to employees as an expenseand a liability of which a current portion is included in accounts payable and other accruals in the accompanyingStatements of Net Position. The amount accrued for compensated absences was $2,677 at June 30, 2024, and $2,485 atJune 30, 2023.Employees receive 10 to 25 vacation days per year based upon length of service. A maximum of two years vacationaccrual may be accumulated, and unused vacation is paid in cash upon separation.Employees primarily receive one day of sick leave for each month of employment with unlimited accumulation. Uponretirement or death, certain employees or their estates receive a percentage of unused sick-leave paid in a lump sumbased on longevity.INSURANCE PROGRAMSThe Water Utility participates in a self-insurance program for workers’ compensation and general liability coverage that isadministered by the City. The Water Utility pays an amount to the City based on actuarial estimates of the amountsneeded to fund prior and current year claims and incidents that have been incurred but not reported. The City maintainsproperty insurance on most City property holdings, including the Utility Plant with a shared limit of $1 billion.City-wide information concerning risks, insurance policy limits and deductibles and designation of general fund balance forrisks for the year ended June 30, 2024, may be found in the notes to the City’s financial statements in the City’s AnnualComprehensive Financial Report.Although the ultimate amount of losses incurred through June 30, 2024 is dependent upon future developments,management believes that amounts paid to the City are sufficient to cover such losses. Premiums paid to the City by theWater Utility were $943 and $786 for the years ended June 30, 2024 and 2023, respectively. Any losses above the City’sreserves would be covered through increased rates charged to the Water Utility in future years.EMPLOYEE RETIREMENT PLANThe City contributes to the California Public Employees Retirement System (CalPERS), an agent multiple employer publicemployee defined benefit pension plan. CalPERS provides retirement and disability benefits, annual cost-of-livingadjustments, and death benefits to plan members and beneficiaries. CalPERS acts as a common investment andadministrative agent for participating public entities within the State of California. Benefit provisions and all otherrequirements are established by state statute and City ordinance.For purposes of measuring the net pension asset/liability and deferred outflows/inflows of resources related to pensions,and pension expense, information about the fiduciary net position of the City of Riverside California Public Employees’Retirement System plans (Plans) and additions to/deductions from the Plans’ fiduciary net position have been determinedon the same basis as they are reported by CalPERS. For this purpose, benefit payments (including refunds of employeecontributions) are recognized when due and payable in accordance with the benefit terms. Investments are reported at fairvalue. Further details of employee retirement plan can be found in Note 6.115NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)OTHER POSTEMPLOYMENT BENEFITS (OPEB)OPEB refers to the benefits, other than pensions, that the City provides as part of an employee’s retirement benefits. Thenet OPEB obligation is defined as the liability of employers contributing to employees for benefits provided through adefined benefit OPEB plan that is administered through a trust. Further details for OPEB can be found in Note 7.DEFERRED OUTFLOWS AND DEFERRED INFLOWS OF RESOURCESWhen applicable, the Statements of Net Position will report a separate section for deferred outflows of resources. Deferredoutflows of resources represent outflows of resources (consumption of net position) that apply to future periods and that,therefore, will not be recognized as an expense or expenditure until that time. Deferred outflows of resources consist ofchanges in derivative values, loss on refunding, and deferred outflows related to pension and OPEB which include pensioncontributions subsequent to the measurement date, difference between actual and actuarial determined contribution,changes in assumptions and net differences between projected and actual earnings on pension plan investments.Conversely, deferred inflows of resources represent inflows of resources (acquisition of net position) that apply to futureperiods, therefore, are not recognized as an inflow of resources (revenue) until that time. Deferred inflows of resourcesconsist of changes in derivative values, lease related items, deferred inflows related to pension and OPEB which includechanges in assumptions, differences between expected and actual experience, and net differences between projected andactual earnings on pension plan investments.REGULATORY ASSETS AND DEFERRED REGULATORY CHARGESIn accordance with regulatory accounting criteria set forth in GASB Codification (GASB Statement No. 62), enterprisefunds that are used to account for rate-regulated activities are permitted to defer certain expenses and revenues thatwould otherwise be recognized when incurred, provided that the Water Utility is recovering or expects to recover or refundsuch amounts in rates charged to its customers. Accordingly, regulatory assets and/or deferred regulatory charges relatedto debt issuance costs have been recognized in the Statements of Net Position.NET POSITIONThe Water Utility’s net position represents the difference between assets and deferred outflows of resources less liabilitiesand deferred inflows of resources, which is classified into the following three components: – this component consists of capital assets (net of accumulated depreciation) reducedby the outstanding balance of any bonds or other borrowings that are attributable to the acquisition, construction, orimprovement of those assets, excluding unspent bond proceeds. – this component represents restricted assets less liabilities and deferred inflows related to those assets.Restricted assets are recorded when there are limitations imposed by creditors (such as through debt covenants),contributors, or laws or regulation of other governments or constraints imposed by law through constitutional provisions orthrough enabling legislation. – this component consists of net position that does not meet the definition of “restricted” or “net investment incapital assets.”CONTRIBUTIONS TO THE CITY’S GENERAL FUNDPursuant to the City of Riverside Charter and the voter approval of Measure A on June 4, 2013, the Water Utility maytransfer up to 11.5 percent of prior year’s gross operating revenues, including adjustments, to the City’s general fund. Infiscal years ended June 30, 2024 and 2023, $8,108 and $8,170, respectively, was transferred, representing 11.5 percent.Additional information can be found in Note 10 of the accompanying financial statements.BUDGETS AND BUDGETARY ACCOUNTINGThe Water Utility presents, and the City Council adopts, a biennial budget. The proposed budget includes estimatedexpenses and forecasted revenues. The City Council generally adopts the Water Utility’s budget in June biennially viaresolution.116NOTES TO THE FINANCIAL STATEMENTS: WATER119 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTSLeases are defined by the general government as the right to use an underlying asset. As lessee, the Water Utilityrecognizes a lease liability and a lease asset at the beginning of a lease period unless the lease is considered a short-termlease or transfers ownership of the underlying asset. Lease assets are measured based on the net present value of thefuture lease payments at inception, using the weighted average cost of capital, which approximate the incrementalborrowing rate. Re-measurement of a lease liability occurs when there is a change in the lease term and/or other changesthat are likely to have a significant impact on the lease liability. The Water Utility calculates the amortization of the discounton the lease liability and report that amount as outflows of resources. Payments are allocated first to accrued interestliability and then to the lease liability. Variable lease payments based on the usage of the underlying assets are notincluded in the lease liability calculations but are recognized as outflows of resources in the period in which the obligationwas incurred. As lessor, the Water Utility recognizes a lease receivable. The lease receivable is measured using the netpresent value of future lease payments to be received for the lease term and deferred inflow of receivables at thebeginning of the lease term. Periodic amortization of the discount on the receivable are reported as interest revenue forthat period. Deferred inflows of resources are recognized as inflows on a straight-line basis over the term of the lease. Thisrecognition does not apply to short-term leases, contracts that transfer ownership, leases of assets that are investments,or certain regulated leases. Any initial direct costs are reported as an outflow of resources for that period. Re-measurement of lease receivables occur when there are modifications, including but not limited to changes in the contractprice, lease term, and adding or removing an underlying asset to the lease agreements. In the case of a partial or full leasetermination, the carrying value of the lease receivable and the related deferred inflow of resources will be reduced and willinclude a gain or loss for the difference. For lease contracts that are short-term, the Water Utility recognizes short-termlease payments as inflows of resources (revenues) based on the payment provisions of the lease contract. Liabilities areonly recognized if payments are received in advance, and receivables are only recognized if payments are receivedsubsequent to the reporting period. Additional disclosures regarding regulated leases are in Note 11. Subscription-Based Information Technology Arrangements (SBITAs) are contracts that convey control of the right to useanother party’s IT software, alone or in combination with tangible capital assets, as specified in the contract for a period oftime in an exchange or exchange-like transaction. To determine whether a contract conveys control of the right to use theunderlying IT assets, the Water Utility assesses both the right to obtain the present service capacity from use of theunderlying IT assets and the right to determine the nature and manner of use of the underlying IT assets as specified inthe contract. Contracts that solely provide IT support services are excluded from the definition of a SBITA. Thesubscription term is the period during which the Water Utility has a noncancellable right to use the underlying IT assets,plus the periods covered by the Water Utility’s option to extend the SBITA if it is reasonably certain, based on all relevantfactors, that the government will exercise that option. Periods for which both the government and the SBITA vendor havean option to terminate the SBITA without permission from the other party (or if both parties have to agree to extend) arecancelable periods and are excluded from the subscription term. Additional disclosures regarding SBITAs are in Note 11.RECLASSIFICATIONSCertain reclassifications have been made to prior year’s financial statements due to error corrections. In fiscal year endedJune 30, 2023, such reclassifications had an effect on the Water Financial Statements inluding a change in net position.Additional information can be found in Note 12 of the accompanying financial statements.117NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTSCash and investments at June 30, 2024 and 2023, consist of the following (in thousands):June 30, 2024June 30, 2023Fair ValueEquity interest in City Treasurer's investment pool$66,442$61,669Cash and cash equivalents at fiscal agent36,39555,488Total cash and investments$102,837$117,157The amounts above are reflected in the accompanying financial statements as:June 30, 2024June 30, 2023Unrestricted cash and cash equivalents$53,449$49,191Restricted cash and cash equivalents12,99312,478Restricted cash and cash equivalents at fiscal agent36,39555,488Total cash and investments$102,837$117,157The investment types in the tables below related to the Water Utility’s investments in the City Treasurer’s investment poolrepresent the Water Utility’s prorated share of the investment types in the investment pool and do not represent ownershipinterests in the individual investments. 118NOTES TO THE FINANCIAL STATEMENTS: WATER121
WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTS (CONTINUED)The Water Utility categorizes its fair value measurements within the fair value hierarchy established by generally acceptedaccounting principles. The Water Utility has the following recurring fair value measurements as of June 30, 2024 and2023:Investment TypeJune 30, 2024Fair ValueQuoted Prices inActive Markets forIdentical Assets(Level 1)Significant OtherObservable Inputs(Level 2)SignificantUnobservableInputs(Level 3)Investmentsnot Subject toFair ValueHierarchyHeld by fiscal agentMoney market funds$36,395$-$-$-$36,395City Treasurer's investment pool1Money market funds63---63Joint powers authority pools 13,542---13,542Mortgage pass-through securities 1,993-1,993--Asset-backed securities5,768-5,768--US Treasury obligations 21,643-21,643--Federal agency obligations 6,143-6,143--Medium-term corporate notes 13,268-13,268--Supranational securities4,022-4,022--Total $102,837$-$52,837$-$50,000Investment TypeJune 30, 2023Fair ValueQuoted Prices inActive Markets forIdentical Assets(Level 1)Significant OtherObservable Inputs(Level 2)SignificantUnobservableInputs(Level 3)Investmentsnot Subject toFair ValueHierarchyHeld by fiscal agentMoney market funds$55,488$-$-$-$55,488City Treasurer's investment pool1Money market funds1,116---1,116Joint powers authority pools 11,896---11,896Mortgage pass-through securities2,031-2,031--Asset backed securities 5,155-5,155--US Treasury obligations17,853-17,853--Federal agency obligations8,538-8,538--Medium-term corporate notes12,849-12,849--Supranational securities2,231-2,231--Total $117,157$-$48,657$-$68,5001Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financialstatements in the City’s Annual Comprehensive Financial Report.119NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTS (CONTINUED)Cash and investments distribution by maturities as of June 30, 2024 and 2023, are as follows:Remaining Maturity (in Months)Investment TypeJune 30, 2024Fair Value12 Monthsor Less13 to 36 Months37 to 60 MonthsHeld by fiscal agentMoney market funds$36,395$36,395$-$-City Treasurer's investment pool1Money market funds6363--Joint powers authority pools 13,54213,542--Mortgage pass-through securities 1,9936082861,099Asset-backed securities5,7683241,9703,474US Treasury obligations 21,643-6,79114,852Federal agency obligations6,1431,8912,5671,685Medium-term corporate notes 13,2682,0255,8465,397Supranational securities4,0222631,4602,299Total$102,837$55,111$18,920$28,806Remaining Maturity (in Months)Investment TypeJune 30, 2023Fair Value12 Monthsor Less13 to 36 Months37 to 60 MonthsHeld by fiscal agentMoney market funds$55,488$55,488$-$-City Treasurer's investment pool1Money market funds1,1161,116--Joint powers authority pools 11,89611,896--Mortgage pass-through securities2,031320737974Asset-backed securities 5,155572,2992,799US Treasury obligations 17,8532,9385,2749,641Federal agency securities 8,5382,0265,1871,325Medium-term corporate notes12,8496416,9925,216Supranational securities 2,231-2,231-Total$117,157$74,482$22,720$19,9551Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financialstatements in the City’s Annual Comprehensive Financial Report.120NOTES TO THE FINANCIAL STATEMENTS: WATER123 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 2.CASH AND INVESTMENTS (CONTINUED)Presented below is the actual rating as of June 30, 2024 and 2023 for each investment type:Rating as of Year EndInvestment TypeJune 30, 2024Fair ValueAAAAAAUnratedHeld by Fiscal AgentMoney Market Funds$36,395$35,238$-$-$1,157City Treasurer's investment pool1Money market funds6363---Joint powers authority pools 13,54213,542---Mortgage pass-through securities 1,9931,808185--Asset-backed securities5,7684,422--1,346US Treasury obligations21,643-21,643--Federal agency obligations 6,143-6,143--Medium-term corporate notes 13,2684024,0876,5112,268Supranational securities4,022---4,022Total$102,837$55,475$32,058$6,511$8,793Rating as of Year EndInvestment TypeJune 30, 2023Fair ValueAAAAAAUnratedHeld by fiscal agentMoney market funds$55,488$55,488$-$-$-City Treasurer's investment pool1Money market funds 1,1161,116---Joint powers authority pools 11,896---11,896Mortgage pass-through securities2,0312,031---Asset backed securities 5,1553,898--1,257US Treasury obligations17,85317,853---Federal agency obligations8,5387,229--1,309Medium-term corporate notes12,8494064,4476,2731,723Supranational securities2,2311,149--1,082Total$117,157$89,170$4,447$6,273$17,2671Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financialstatements in the City’s Annual Comprehensive Financial Report.121NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 3.CAPITAL ASSETSThe following is a summary of changes in utility plant and lease and subscription assets during the fiscal years ended June30, 2024 and 2023 (in thousands):BalanceAs of6/30/2022AdditionsRetirements/TransfersBalanceAs of6/30/2023AdditionsRetirements/TransfersBalanceAs of6/30/2024Source of supply$80,886$1,046$-$81,932$3,182$-$85,114Pumping35,2134,759(3)39,9693,629-43,598Treatment44,7941,066-45,86029-45,889Transmission and distribution539,65613,827(1,365)552,11814,539(1,305)565,352General18,275704(254)18,725814(236)19,303Intangible4,181--4,181--4,181Depreciable utility plant723,00521,402(1,622)742,78522,193(1,541)763,437Less accumulated depreciationSource of supply(25,655)(2,054)-(27,709)(2,058)-(29,767)Pumping(15,768)(756)-(16,524)(815)-(17,339)Treatment(18,926)(1,282)-(20,208)(1,319)-(21,527)Transmission and distribution(206,173)(11,578)1,352(216,399)(11,889)891(227,397)General(13,761)(576)248(14,089)(643)236(14,496)Intangible(4,021)(122)-(4,143)(30)-(4,173)Accumulated depreciation(284,304)(16,368)1,600(299,072)(16,754)1,127(314,699)Net depreciable utility plant438,7015,034(22)443,7135,439(414)448,738Land20,841--20,84146(17)20,870Intangible, non-amortizable10,845--10,845--10,845Construction in progress37,90720,204(16,056)42,05530,152(18,197)54,010Nondepreciable utility plant69,59320,204(16,056)73,74130,198(18,214)85,725Total utility plant, net$508,294$25,238$(16,078)$517,454$35,637$(18,628)$534,463Lease and subscription assets, beingamortized1Machinery and equipment-Intangible21--2121(16)26Subscription-based information technologyarrangements-32-321-33Total lease and subscription assets2132-5322(16)59Less lease accumulated amortizationMachinery and equipment-Intangible(5)(5)-(10)(5)9(6)Subscription-based information technologyarrangements-(15)-(15)(10)-(25)Total lease accumulated amortization(5)(20)-(25)(15)9(31)Total lease and subscription assets, net 1612-287(7)28Total capital assetsbeing depreciated, net$508,310$25,250$(16,078)$517,482$35,644$(18,635)$534,4911GASB 87 Leases was implemented effective July 1, 2021. GASB 96 Subscription-Based Information Technology Arrangements (SBITA) wasimplemented effective July 1, 2022. For additional information, refer to Notes 1 and 11. 122122NOTES TO THE FINANCIAL STATEMENTS: WATER125 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONSThe following is a summary of changes in long-term obligations during the fiscal years ended June 30, 2024 and 2023 (inthousands):BalanceAs of6/30/2022AdditionsReductionsBalanceAs of6/30/2023AdditionsReductionsBalanceAs of6/30/2024Due WithinOne YearRevenue bonds$209,662$63,596$(7,964)$265,294$-$(9,129)$256,165$8,460Arbitrage liability----673-673-Pension obligation bonds21,287-(1,363)19,924-(1,640)18,2841,815Direct borrowings:Financed purchases1,218-(233)985-(237)748243Contracts payable - water stockacquisition rights933--933-(2)931150Total long-term obligations$233,100$63,596$(9,560)$287,136$673$(11,008)$276,801$10,668Long-term debt consists of the following (in thousands):CONTRACTS PAYABLEJune 30, 2024June 30, 2023Water Stock Acquisitions: Payable to various water companies$931$933Total contracts payable931933PENSION OBLIGATION BONDS PAYABLEJune 30, 2024June 30, 2023$31,960 2017 Taxable Pension Obligation Bonds Series A: fixed rate bonds issued by the City due in annualinstallments from $2,910 to $3,580 through June 2027, with coupons from 1.3 to 3.1 percent. The Water Utility'sproportional share of the outstanding debt is 10.7 percent.$1,114$1,465$201,080 2020 Taxable Pension Obligation Bonds Series A (Miscellaneous): fixed rate bonds issued by theCity due in annual installments from $1,285 to $14,625 through June 2045, with coupons from 1.7 to 3.9 percent.The Water Utility's proportional share of the outstanding debt is 10.2 percent.17,17018,459Total pension obligation bonds payable18,28419,924REVENUE BONDS PAYABLEJune 30, 2024June 30, 2023$67,790 2009 Water Revenue Series B Bonds: fixed rate, federally taxable, Build America Bonds due in annualprincipal installments from $2,475 to $4,985 from October 1, 2021 through October 1, 2039, interest from 5.1 to 6.4percent, excluding 33% sequestration credit from the IRS, effective October 1, 2020.$60,115$62,760$59,000 2011 Water Revenue/Refunding Series A Bonds: variable rate bonds due in annual principalinstallments from $600 to $3,950 through October 1, 2035. Interest rate is subject to daily repricing (net interestrate, including swaps, at June 30, 2019 was 3.1 percent). Partially refunded $26,900 on April 1, 2019 with 2019AWater Refunding Bonds.24,05024,050$114,215 2019 Water Revenue Refunding Series A Bonds: fixed rate bonds due in annual principal installmentsfrom $1,680 to $8,455 through October 1, 2048, interest of 5.0 percent.93,89598,465$58,025 2022 Water Revenue Series A Bonds: fixed rate bonds due in annual principal installments from $735 to$3,605 through October 1, 2052, interest of 5.0 percent.57,29058,025Total water revenue bonds payable235,350243,300Total water revenue bonds, pension obligation bonds and contracts payable254,565264,157Unamortized bond premium20,81521,994Total water revenue bonds, pension obligation bonds and contracts payable, including bond premium275,380286,151Less current portion(10,425)(9,740)Total long-term water revenue bonds, pension obligation bonds and contracts payable$264,955$276,411123NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED) - The Water Utility is obligated to pay its share of the City's pension obligation bonds (POB),which the City issued in 2005 and refinanced a portion in May 2017. The bond proceeds were deposited with CalPERS tofund the unfunded actuarial accrued liability for non-safety employees.In fiscal year ended June 30, 2020, the City issued $432,165 2020 Taxable Pension Obligation Bonds Series A. The bondswere issued to reduce the City's unfunded pension liability in both the City's Miscellaneous and Safety CalPERS plans. It isestimated the issuance will save the City's General Fund approximately $178.5 million throughout the life of the bonds.The fixed rate bonds issued by the City under the miscellaneous plan are due in annual installments from $1,285 to$14,625 through June 2045, with coupons from 1.7% to 3.9%. The Water Utility's proportional share of the miscellaneousplan is 10.2%.The Water Utility's proportional share of the outstanding principal amount of both pension obligation bonds was $18,284and $19,924 as of June 30, 2024 and 2023, respectively. For more discussion relating to the City's pension obligation bondissuance, see the notes to the City's financial statements in the City's Annual Comprehensive Financial Report for thefiscal year ended June 30, 2024. Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund.As of June 30, 2024, the annual debt service requirements to maturity are as follows (in thousands):Fiscal YearPrincipalInterestTotal2025$1,815$605$2,42020261,8675622,42920271,7935142,30720281,1824651,64720299414321,3732030-20344,3231,7526,0752035-20394,6318475,4782040-20431,7321261,858Total$18,284$5,303$23,587As of June 30, 2023, the annual debt service requirements to maturity were as follows (in thousands):Fiscal YearPrincipalInterestTotal2024$1,640$642$2,28220251,8156052,42020261,8675622,42920271,7935142,30720281,1824651,6472029-20334,2821,9006,1822034-20384,8231,0335,8562039-20432,5222242,746Total$19,924$5,945$25,869 - All water revenue bonds are covenanted per the Amended and Restated Resolution No. 17664 (Water)Master Resolution that upon the occurrence and continuation of an event of default, the owners of 25% in aggregateamount of Bond Obligation may, by written notice to the City, declare the entire unpaid principal and accreted value of thebonds due and payable should the City fail to pay its debts as they become due or upon the entry of any decree or order ofbankruptcy of the City.The Tax Reform Act of 1986 (the Act) requires the Water Utility to calculate and remit rebatable arbitrage earnings to theInternal Revenue Service. Certain debt and interest earnings on the proceeds of the Water Utility are subject to therequirements of the Act, which contain yield restrictions on investment of proceeds from tax-exempt financing in higher-yielding taxable securities. The balance in the arbitrage liability as of June 30, 2024 was $673 and is included in long-termobligations, less current portion, in the accompanying Statements of Net Position.124NOTES TO THE FINANCIAL STATEMENTS: WATER127 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)$58,025 Water Revenue Bonds Series A. The bonds were issued in December 2022 to fund short-term and long-termcapital projects. Interest on the bonds is 5%, payable in April and October of each year. Principal payments are due inannual installments through October 1, 2052, and range from $735 to $3,605. Remaining revenue bond debt service payments will be made from revenues of the Water Fund. As of June 30, 2024, the annual debt service requirements to maturity are as follows (in thousands):Fiscal YearPrincipalInterestTotal2025$8,460$10,664$19,12420268,84010,25719,09720279,2459,83119,07620289,6659,38519,050202910,0958,92019,0152030-203456,48537,48193,9662035-203969,01524,00393,0182040-204424,81512,36437,1792045-204925,3156,64231,9572050-205314,0881,38315,471Premium20,815-20,815Total$256,838$130,930$387,768As of June 30, 2023 the annual debt service requirements to maturity are as follows (in thousands):Fiscal YearPrincipalInterestTotal2024$7,950$11,050$19,00020258,46010,66419,12420268,84010,25719,09720279,2459,83119,07620289,6659,38519,0502029-203354,43039,88394,3132034-203866,10027,02293,1222039-204335,51513,81749,3322044-204824,1107,87831,9882049-205318,9852,19321,178Premium21,994-21,994Total$265,294$141,980$407,274Pledged Revenue - The Water Utility has a number of debt issuances (revenue bonds) outstanding that are collateralizedby the pledging of water revenues. The amount and term of the remainder of these commitments are indicated in therevenue bonds payable and annual debt service requirements to maturity tables presented within this Note 4. The purposeof the debt issuances was for the financing of various Water Utility capital improvement projects. For June 30, 2024 and 2023, debt service payments as a percentage of the pledged gross revenue, net of certainexpenses where so required by the debt agreement, are indicated in the table below. The debt service coverage ratiosalso approximate the relationship of the debt service to pledged revenue for the remainder of the term of the commitment.125125NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)Fiscal Year EndedDescription ofPledged RevenuesAnnual Amount ofPledged Revenue(net of expenses) 1, 2, 3, 4, 5Annual Debt ServicePaymentsDebt ServiceCoverage Ratio5June 30, 2024Water revenues$41,463$20,9141.98June 30, 2023Water revenues$36,781$18,8481.951Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of $2,483 and $(471) for June 30, 2024 and 2023,respectively.2Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $173 and $168for June 30, 2024 and 2023, respectively.3Includes GASB 87 Leases net revenue adjustment of $3,023 and $2,957 for June 30, 2024 and 2023, respectively.4Includes rebatable arbitrage of $673 for June 30, 2024.5As restated for fiscal year ended June 30, 2023. LINE OF CREDITOn February 1, 2019, the City entered into a subordinate line of credit agreement with U.S. Bank, National Association.The agreement was renewed on February 1, 2022. The Subordinate Line of Credit is a tool approved through the Electricand Water Utility Five-Year Rate Plan to manage rate increases by enabling the Water Utility to reduce cash levels whilemaintaining compliance with the Riverside Public Utilities Cash Reserve Policy. Under the terms and conditions of theagreement, the City may borrow up to $25,000 for purposes of the capital or operating financial needs of the WaterSystem. There were no borrowings against the line as of June 30, 2024 and 2023.LETTERS OF CREDITThe Water Utility’s Issue of the 2011A Water Revenue Bonds require an additional layer of security between the WaterUtility and the purchaser of the bonds. As of June 30, 2024 and 2023, the Water Utility had the following letter of credit (LOC) to provide liquidity should all or aportion of the debt be optionally tendered to the remarketer without being successfully remarketed: Debt IssueLOC ProviderLOCExpirationDateAnnualCommitmentFee2011A Water Revenue BondsPNC Bank, NA2025%0.230To the extent that remarketing proceeds are insufficient or not available, tendered amounts will be paid from drawingsmade under an irrevocable direct-pay letter of credit. INTEREST RATE SWAPS ON REVENUE BONDSThe Water Utility has one cash flow hedging derivative instrument, which is a pay-fixed swap. The swap was employed asa hedge against debt that was refunded in 2008 and 2011. At the time of the refunding, hedge accounting ceased to beapplied. The balance of the deferral account for the swap is included as part of the deferred loss on refunding associatedwith the new bonds. The swap was also employed as a hedge against the new debt. Hedge accounting was applied to thatportion of the hedging relationship, which was determined to be effective. The negative fair value of the interest rate swapsrelated to the new hedging relationship has been recorded and deferred on the Statements of Net Position.A summary of the derivative activity for the year ended June 30, 2024 is as follows:NotionalAmountFair Valueas ofJune 30, 2024Change inFair Valuefor Fiscal Year2011 Water Refunding/Revenue Bonds Series A$24,050$(831)$546126NOTES TO THE FINANCIAL STATEMENTS: WATER129 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)A summary of the derivative activity for the year ended June 30, 2023 was as follows:NotionalAmountFair Valueas ofJune 30, 2023Change inFair Valuefor Fiscal Year2011 Water Refunding/Revenue Bonds Series A$24,050$(1,377)$1,269Objective:In order to lower borrowing costs as compared to fixed-rate bonds, the Water Utility entered into an interestrate swap agreement in connection with its $59,000 2011 Water Refunding/Revenue Series A Bonds.Terms: As of June 30, 2024, per the existing swap agreement, the Water Utility pays the counterparty a fixed paymentand receives a variable payment computed as 62.68% of the Secured Overnight Financing Rate (“SOFR”) one-monthindex plus 12 basis points. The swap has a notional amount equal to the remaining principal amount stated above. Thenotional value of the swap and principal amount of the associated debt decline by $2,375 to $3,950 until the debt iscompletely retired in fiscal year 2036. The bonds and the related swap agreement for the 2011 Water Refunding/RevenueSeries A Bonds mature on October 1, 2035. As of June 30, 2023, per the existing swap agreement, the Water Utility payed the counterparty a fixed payment andreceived a variable payment computed as 62.68% of the London Interbank Offering Rate (“LIBOR”) one-month index plus12 basis points. The swap had a notional amount equal to the principal amount stated above. The notional value of theswap and principal amount of the associated debt declined by $1,475 to $3,950 until the debt would be completely retiredin fiscal year 2036.Replacement of LIBOR: As of July 1, 2023, LIBOR was no longer an appropriate benchmark interest rate for a derivativeinstrument that hedges the interest risk for taxable debt for purposes of GASB Statement 53.As of June 30, 2024 and 2023, the rates were as follows:Interest rate swap:TermsRatesFixed payment to counterpartyFixed%3.20000Variable payment from counterparty62.68 SOFR + 12bps%(0.93099)Net interest rate swap payments%2.26901Variable-rate bond coupon payments %0.81071Synthetic interest rate on bonds%3.07972Interest rate swap:TermsRatesFixed payment to counterpartyFixed%3.20000Variable payment from counterparty62.68 LIBOR + 12bps%(0.72101)Net interest rate swap payments%2.47899Variable-rate bond coupon payments %0.65145Synthetic interest rate on bonds%3.13044Fair value:As of June 30, 2024 and 2023, in connection with the swap agreement, the transactions had a total fair valueof $(831) and $(1,377), respectively. Because the coupons on the Water Utility’s variable-rate bonds adjust to changinginterest rates, the bonds do not have a corresponding fair value decrease. The fair value was developed by a pricingservice using the zero-coupon method. This method calculates the future net settlement payments required by the swap,assuming that the current forward rates implied by the yield curve correctly anticipate future spot interest rates. Thesepayments are then discounted using the spot rates implied by the current yield curve for hypothetical zero-coupon bondsdue on the date of each future net settlement of the swap.127NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)Credit risk:As of June 30, 2024 and 2023, the Water Utility was not exposed to credit risk because the swap had anegative fair value. The swap counterparty, J.P. Morgan Chase & Co., was rated A- by Standard & Poor's (S&P). Tomitigate the potential for credit risk, the swap agreement requires the fair value of the swap to be collateralized by thecounterparty with U.S. Government securities if the counterparty’s rating decreases to negotiated trigger points. Collateralwould be posted with a third-party custodian. At June 30, 2024 and 2023, there is no requirement for collateral posting forthe outstanding swap.Basis risk:As of June 30, 2024, the swap exposes the Water Utility to basis risk should the relationship between SOFRand the variable interest rates converge, changing the synthetic rate on the bonds. If a change occurs that results in therates moving to convergence, the expected cost savings may not be realized.As of June 30, 2023, the swap exposed the Water Utility to basis risk should the relationship between LIBOR and thevariable interest rates converge, changing the synthetic rate on the bonds. If a change would have occued that results inthe rates moving to convergence, the expected cost savings might not have been realized.Termination risk:The derivative contract uses the International Swap Dealers Association Master Agreement, whichincludes standard termination events, such as failure to pay and bankruptcy. The Schedule to the Master Agreementincludes an “additional termination event.” That is, a swap may be terminated by the Water Utility if the counterparty’scredit quality falls below “BBB-” as issued by S&P. The Water Utility or the counterparty may terminate a swap if the otherparty fails to perform under the terms of the contract. If a swap is terminated, the variable-rate bond would no longer carrya synthetic interest rate. Also, if at the time of termination a swap has a negative fair value, the Water Utility would be liableto the counterparty for a payment equal to the swap’s fair valueSwap payments and associated debt:As of June 30, 2024 and 2023, the debt service requirements of the variable-ratedebt and net swap payments, assuming current interest rates remain the same for their term, are summarized as follows.As rates vary, variable-rate bond interest payments and net swap payments will vary.Variable-Rate Bondsas of June 30, 2024Fiscal YearEndingJune 30,PrincipalInterestInterest RateSwaps, NetTotal2025$-$208$581$7892026-2085817892027-2085817892028-2085817892029-2085817892030-203416,2756511,82218,7482035-20397,775511437,969Total$24,050$1,742$4,870$30,662128NOTES TO THE FINANCIAL STATEMENTS: WATER131 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 4.LONG-TERM OBLIGATIONS (CONTINUED)INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)Variable-Rate Bondsas of June 30, 2023Fiscal YearEndingJune 30,PrincipalInterestInterest RateSwaps, NetTotal2024$-$164$625$7892025-1646257892026-1646257892027-1646257892028-1646257892029-203312,5756192,35715,5512034-203811,47510037911,954Total$24,050$1,539$5,861$31,450FINANCED PURCHASESIn fiscal year ended June 30, 2017, the Water Utility participated in the City’s purchase financing program for theacquisition of water system heavy vehicles and equipment. The heavy vehicles and equipment financed purchases are fora ten-year term of annual payments with an interest rate of 2.36%. Gross proceeds of $2,305 were received for thefinancing. As of June 30, 2024 and 2023, the total outstanding liability, including current portion was $748 and $985, respectively.The annual payments for the life of the agreements are $260 annually through fiscal year ending June 30, 2027. As ofJune 30, 2024, total outstanding payments are $779, with $748 representing principal and $31 representing interest. As ofJune 30, 2023, total outstanding payments are $1,039, with $985 representing principal and $54 representing interest. 5.COMPENSATED ABSENCESA liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement tothese balances are attributable to services already rendered and it is probably that virtually all of these balances will beliquidated by either paid time-off or payments upon termination or retirement.Below is a summary of changes in compensated absences for the Water Utility as of June 30, 2024 and 2023:BalanceAs of6/30/2022AdditionsReductionsBalanceAs of6/30/2023AdditionsReductionsBalanceAs of6/30/2024Due Within OneYearCompensated absences$2,573$1,940$(2,028)$2,485$2,081$(1,889)$2,677$2,034129NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLANPLAN DESCRIPTIONThe Water Utility's employees participate in the City’s Miscellaneous (non-safety) Plan (the Plan), an agent multipleemployer public employee defined benefit pension plan. CalPERS provides retirement and disability benefits, annual cost-of-living adjustments, and death benefits to plan members and beneficiaries. CalPERS acts as a common investment andadministrative agent for participating public entities within the State of California. CalPERS issues a publicly availablefinancial report that includes financial statements and required supplementary information for the cost sharing plans thatare administered by CalPERS. Benefit provisions and all other requirements are established by state statute and Cityordinance. A copy of CalPERS’ annual financial report may be obtained online at www.calpers.ca.gov. The Water Utilityparticipates in the City’s Miscellaneous (non-safety) Plan (the Plan).FUNDING POLICYThe City has contributed at the actuarially determined rate provided by CalPERS’ actuaries. Participants are required tocontribute 8% of their annual covered salary. The City has a multiple tier retirement plan with benefits varying by plan. Allpermanent full-time and selected part-time employees are eligible for participation in CalPERS. Benefits vest after fiveyears of service and are determined by a formula that considers the employee’s age, years of service and salary. Underthe Plan, the City pays the employees’ contribution to CalPERS for employees hired on or before specific dates as follows:1stTier –The retirement formula is 2.7% at age 55 for employees hired on or before October 18, 2011. EffectiveJanuary 1, 2018 for unrepresented employees (Sr. Management, Management, Professional, Para-professional, Supervisory, Confidential, and Executive units, excluding the Chief of Police and the FireChief), the employees were required to pay 2% of their pensionable income, with the City contributing theother 6%. Effective January 1, 2019, employees were required to pay an additional portion of theirpensionable income. This portion is a three-year increase of 2% (2019), 2% (2020) and 2% (2021). As of2021, employees are contributing the entire 8% of their pensionable income.The retirement formula is 2.7% at age 55 for SEIU and SEIU Refuse employees hired before June 7, 2011.Currently, employees are required to pay 7% of their pensionable income with the City contributing the other1%. Effective January 1, 2019, employees were required to pay an additional portion of their pensionableincome. This portion is a two-year increase of 1% (2019) and 1% (2020). As of 2020, employees arecontributing the entire 8% of their pensionable income.The retirement formula is 2.7% at age 55 for IBEW and IBEW Supervisory employees hired on or beforeOctober 18, 2011. Effective November 1, 2017 employees were required to pay 2% of their totalpensionable income with the City paying the remaining 6%. Effective each November 1st, employees will berequired to pay an additional portion of their pensionable income. This portion is a three-year increase of 2%(2018), 2% (2019) and 2% (2020). As of November 2020, employees are contributing the entire 8% of theirpensionable income.2ndTier - The retirement formula is 2.7% at age 55, and:Miscellaneous employees, IBEW, and IBEW Supervisory hired on or after October 19, 2011 pay their share(8%) of contributions.SEIU and SEIU Refuse employees hired on or after June 7, 2011 pay their share (8%) of contributions.3rd Tier – The retirement formula is 2% at age 62 for new members hired on or after January 1, 2013 and theemployee must pay the normal cost to CalPERS which is currently at 8.25%. Classic members (CalPERSmembers prior to 12/31/12) hired on or after January 1, 2013 may be placed in a different tier.The contribution requirements of plan members and the City are established and may be amended by CalPERS.130NOTES TO THE FINANCIAL STATEMENTS: WATER133 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)BENEFITS PROVIDEDCalPERS provides service retirement and disability benefits, annual cost of living adjustments and death benefits to planmembers, who must be public employees and beneficiaries. Benefits are based on years of credited service, equal to oneyear of full-time employment. Members with five years of total service are eligible to retire at age 50 with statutorily reducedbenefits. All members are eligible for non-duty disability benefits after five years of service. The death benefit is one of thefollowing: the Basic Death Benefit, the 1959 Survivor Benefit Level III, or the Optional Settlement 2W Death Benefit. Thecost of living adjustments for the Plan are applied as specified by the Public Employees’ Retirement Law.CONTRIBUTIONSSection 20814(c) of the California Public Employees’ Retirement Law requires that the employer contribution rates for allpublic employers be determined on an annual basis by the actuary and shall be effective on the July 1 following notice of achange in the rate. Funding contributions for the Plan is determined annually on an actuarial basis as of June 30 byCalPERS. The actuarially determined rate is the estimated amount necessary to finance the costs of benefits earned byemployees during the year, with an additional amount to finance any unfunded accrued liability. The City is required tocontribute the difference between the actuarially determined rate and the contribution rate of employees.NET PENSION LIABILITYThe City’s net pension liability for the Plan is measured as the total pension liability, less the pension plan’s fiduciary netposition. For fiscal year ended June 30, 2024, the net pension liability of the Plan is measured as of June 30, 2023, usingan annual actuarial valuation as of June 30, 2022 rolled forward to June 30, 2023 using standard update procedures. Forfiscal year ended June 30, 2023, the net pension liability of the Plan is measured as of June 30, 2022, using an annualactuarial valuation as of June 30, 2021 rolled forward to June 30, 2022 using standard update procedures. A summary ofprincipal assumptions and methods used to determine the net pension liability is shown below.ACTUARIAL ASSUMPTIONSThe total pension liabilities in the June 30, 2023 and 2022 actuarial valuations were determined using the followingactuarial assumptions:MiscellaneousCurrent YearMiscellaneousPrior YearValuation DateJune 30, 2022June 30, 2021Measurement DateJune 30, 2023June 30, 2022Actuarial Cost MethodEntry-Age Normal Cost MethodEntry-Age Normal Cost MethodActuarial AssumptionsDiscount Rate6.90% 6.90%Inflation2.30% 2.30%Salary IncreaseVaries by entry age and serviceVaries by entry age and serviceMortality Rate Table1Derived using CalPERS’ membership data for all funds.Post Retirement BenefitIncreaseThe lesser of contract COLA or 2.30% untilPurchasing Power Protection Allowance floor onpurchasing power applies, 2.30% thereafterThe lesser of contract COLA or 2.30% untilPurchasing Power Protection Allowance floor onpurchasing power applies, 2.30% thereafter1The mortality table used was developed based on CalPERS-specific data. The probabilities of mortality are based on the 2021 CalPERS Experience Study for the period from2001 to 2019. Pre-retirement and Post-retirement mortality rates include generational mortality improvement using 80% of Scale MP-2020 published by the Society of Actuaries.For more details on this table, please refer to the CalPERS Experience Study and Review of Actuarial Assumptions report from November 2021 that can be found on theCalPERS website.131NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)LONG-TERM EXPECTED RATE OF RETURNThe long-term expected rate of return on pension plan investments was determined using a building-block method inwhich expected future real rates of return (expected returns, net of pension plan investment expense and inflation) aredeveloped for each major asset class.In determining the long-term expected rate of return, CalPERS took into account both short-term and long-term marketreturn expectations. Using historical returns of all of the funds’ asset classes, expected compound (geometric) returnswere calculated over the next 20 years using a building-block approach. The expected rate of return was then adjusted toaccount for assumed administrative expenses of 10 Basis points. The expected real rates of return by asset class are asfollows: June 30, 2023 Measurement DateAsset Class (1)Assumed AssetAllocation Real Return(1),(2)Global Equity - Cap-weighted30.00%4.54%Global Equity - Non-Cap-weighted12.00%3.84%Private Equity13.00%7.28%Treasury5.00%0.27%Mortgage-backed Securities5.00%0.50%Investment Grade Corporates10.00%1.56%High Yield5.00%2.27%Emerging Market Debt5.00%2.48%Private Debt5.00%3.57%Real Assets15.00%3.21%Leverage(5.00)%(0.59)%(1) An expected inflation of 2.30% used for this period.(2) Figures are based on the 2021 Asset Liability Management study.June 30, 2022 Measurement DateAsset Class (1)Assumed AssetAllocation Real Return(1),(2)Global Equity - Cap-weighted30.00%4.54%Global Equity - Non-Cap-weighted12.00% 3.84%Private Equity13.00% 7.28%Treasury5.00% 0.27%Mortgage-backed Securities5.00% 0.50%Investment Grade Corporates10.00% 1.56%High Yield5.00% 2.27%Emerging Market Debt5.00% 2.48%Private Debt5.00% 3.57%Real Assets15.00% 3.21%Leverage(5.00)% (0.59)%(1) An expected inflation of 2.30% used for this period.(2) Figures are based on the 2021 Asset Liability Management study.132132NOTES TO THE FINANCIAL STATEMENTS: WATER135 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)DISCOUNT RATEThe discount rate used to measure the total pension liability was 6.90% and 6.90% for measurement dates as of June 30,2023 and 2022, respectively. The projection of cash flows used to determine the discount rate assumed that contributionsfrom plan members will be made at the current member contribution rates and that contributions from employers will bemade at statutorily required rates, actuarially determined. Based on those assumptions, the Plan’s fiduciary net positionwas projected to be available to make all projected future benefit payments of current plan members. Therefore, the long-term expected rate of return on plan investments was applied to all periods of projected benefit payments to determine thetotal pension liability.Changes of Benefit Terms - In 2022, SB 1168 increased the standard retiree lump sum death benefit from $500 to $2,000for any death occurring on or after July 1, 2023. The impact, if any, is included in the changes of benefit terms.CHANGES IN ASSUMPTIONSEffective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from7.15% to 6.90%. In determining the long-term expected rate of return, CalPERS took into account long-term market returnexpectations as well as the expected pension fund cash flows. Projected returns for all asset classes were estimated,combined with risk estimates, and used to project compound (geometric) returns over the long term. The discount rateused to discount liabilities was informed by the long-term projected portfolio return. In addition, demographic assumptionsand the inflation rate assumption were changed in accordance with the 2021 CalPERS Experience Study and Review ofActuarial Assumptions.There were no assumption changes in valuation dated June 30, 2022 (2023 measurement date). CHANGES IN THE NET PENSION LIABILITY (ASSET)The changes in the Water Utility’s proportionate share of the net pension liability/(asset) as of June 30, 2024(measurement date June 30, 2023) and 2023 (measurement date June 30, 2022) for the Plan are as follows:June 30, 2024Net PensionLiability/(Asset)Proportion ofthe PlanProportion - Reporting date June 30, 2024 (Measurement Date June 30, 2023)$14,455%9.33Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022)12,854%9.76Changes - Increase / (Decrease)1,601%(0.43)June 30, 2023Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022)$12,854%9.76Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021)(8,809)%9.93Changes - Increase / (Decrease)21,663%-0.17133133NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TOPENSIONFor the fiscal years ended June 30, 2024 and 2023, the Water Utility recognized pension expense of $4,463 and $2,373,respectively. At June 30, 2024 and 2023, the Water Utility reported deferred outflows/(inflows) of resources related topension from the following sources:June 30, 2024June 30, 2023DeferredOutflows ofResources DeferredInflows ofResources DeferredOutflows ofResources DeferredInflows ofResources Pension contributions subsequent tomeasurement date$1,981$-$2,844$-Change of assumptions688-1,321-Difference between expected and actualexpense 819(618)87(1,187)Net difference between projected andactual earnings on pension planinvestments6,650-7,336-Total$10,138$(618)$11,588$(1,187)Deferred outflows of resources related to contributions subsequent to the measurement date reported in prior year wasrecognized as a reduction of the net pension liability in the year ended June 30, 2025 and 2024, respectively.At June 30, 2024 and 2023, the Water Utility reported deferred outflows/(inflows) of resources related to pension to berecognized as pension expense as follows:Year EndedJune 30Deferred Outflows/(Inflows) ofResources2025$1,66720261,04220274,6322028198Total$7,539Year EndedJune 30Deferred Outflows/(Inflows) ofResources2024$1,34320251,151202649720274,566Total$7,557134134NOTES TO THE FINANCIAL STATEMENTS: WATER137 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 6.EMPLOYEE RETIREMENT PLAN (CONTINUED)PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TOPENSION (CONTINUED)On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for fiscal year 2020-21. Based on thethresholds specified in CalPERS Funding Risk Mitigation policy, the excess return of 14.3% prescribed a reduction ininvestment volatility that corresponds to a reduction in the discount rate used for funding purposes of 0.20%, from 7.00%to 6.80%. Since CalPERS was in the final stages of the four-year Asset Liability Management (ALM) cycle, the boardelected to defer any changes to the asset allocation until the ALM process concluded, and the board could make its finaldecision on the asset allocation in November 2021.On November 17, 2021, the board adopted a new strategic asset allocation. The new asset allocation along with the newcapital market assumptions, economic assumptions and administrative expense assumption support a discount rate of6.90% (net of investment expense but without a reduction for administrative expense) for financial reporting purposes. Thisincludes a reduction in the price inflation assumption from 2.50% to 2.30% as recommended in the November 2021CalPERS Experience Study and Review of Actuarial Assumptions. This study also recommended modifications toretirement rates, termination rates, mortality rates and rates of salary increases that were adopted by the board. Thesenew assumptions will be reflected in the GASB 68 accounting valuation reports for the June 30, 2022, measurement date.Events Subsequent to June 30, 2022 valuation date (2023 measurement date) - There were no subsequent events thatwould materially affect the results in this disclosure.SENSITIVITY OF THE NET PENSION LIABILITY (ASSET) TO CHANGES IN THE DISCOUNT RATEThe following presents the Water Utility’s proportionate share of the net pension liability of the Plan, calculated using thediscount rate of 6.90% (measurement date June 30, 2023), and 6.90% (measurement date June 30, 2022) as well as whatthe Water Utility’s proportionate share of the net pension liability would be if it was calculated using a discount rate that is1-percentage point lower or 1-percentage point higher than the current rate:Measurement DateJune 30, 2023Measurement DateJune 30, 2022Discount Rate-1%(5.90%)CurrentDiscount Rate(6.90%)Discount Rate+1%(7.90%)Discount Rate-1%(5.90%)CurrentDiscount Rate(6.90%)Discount Rate+1%(7.90%)Water Utility'sproportionate share of thePlan's net pensionliability/(asset)$35,475$14,455$(28,190)$34,227$12,854$(4,696)Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports.135NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB)PLAN DESCRIPTIONEmployees of the Water Utility participate in the City’s defined benefit OPEB plan, Retiree Health Plan, providescontinuation of medical (including prescription drugs) and dental coverage benefits to retirees and surviving spouses in theform of an implied rate subsidy. The Retiree Health Benefits plan is a single employer defined benefit OPEB planadministered by the City. No assets are accumulated in a trust that meets the criteria in paragraph 4 of GASB StatementNo. 75.BENEFITS PROVIDED Eligibility for continuation of coverage requires retirement from the City and CalPERS with at least 5 years of City service.The retiree is responsible for 100% of the premium cost for coverage, which is based on the blended experience of boththe active and retired employees. The City is not required by law or contractual agreement to provide funding other thanthe pay-as-you-go amount necessary to provide current benefit to eligible retirees and beneficiaries. Retiree and spousalcoverage terminates when the retiree becomes covered under another employer health plan, or when the retiree reachesMedicare eligibility age, which is currently age 65. However, retiree benefit continues to the surviving spouse if the retireeelects the CalPERS survivor annuity.ACTUARIAL ASSUMPTIONSThe total OPEB liability was determined by actuarial valuation as of June 30, 2023 and 2022, using the following actuarialassumptions:Miscellaneous - Current YearMiscellaneous - Prior YearValuation DateJune 30, 2023June 30, 2021Measurement DateJune 30, 2023June 30, 2022Actuarial Cost MethodPay-as-you-go for implicit rate subsidyPay-as-you-go for implicit rate subsidyActuarial AssumptionsDiscount RateBond Buyer 20 Index at June 30, 2023resulting in a rate of 3.65%Bond Buyer 20 Index at June 30, 2022resulting in a rate of 3.54%Inflation Rate2.50% per annum2.50% per annumPayroll Increases2.75% per year. Since benefits do notdepend on salary (as they do for pensions),this assumption is only used to determinethe accrual pattern of the Actuarial PresentValue of Projected Benefit Payments.2.75% per year. Since benefits do notdepend on salary (as they do for pensions),this assumption is only used to determinethe accrual pattern of the Actuarial PresentValue of Projected Benefit Payments.Mortality2021 CalPERS Retiree Mortality Table forthe appropriated population2017 CalPERS Retiree Mortality Table forthe appropriated populationHealthcare TrendRatesMedical trend in future years has beenupdated to 4.00% for all years.Medical trend in future years has beenupdated to 4.00% for all years from 6.25%tiered down by 0.25% per year to 4.50% inall future years.CHANGES OF ASSUMPTIONSIn 2023, the discount rate was changed from 3.54% to 3.65%. In 2022, the discount rate was changed from 2.16% to3.54%.136NOTES TO THE FINANCIAL STATEMENTS: WATER139 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN HEALTHCARE COST TREND RATESThe following presents the Water Utility’s proportionate share of the City’s total OPEB liability, calculating using thehealthcare trend rate of 4.00% for measurement date as of June 30, 2023 and June 30, 2022, as well as what the WaterUtility’s total OPEB liability would be if it was calculated using a healthcare cost trend rate that is 1-percentage-point loweror 1-percentage-point higher than the current rate:Measurement DateJune 30, 2023Measurement DateJune 30, 20221% DecreaseCurrenthealthcarecost trend rate4%1% Increase1% DecreaseCurrenthealthcarecost trend rate4%1% IncreaseWater Utility's proportionate share of thetotal OPEB liability$2,924$4,265$3,793$3,546$4,043$4,609SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN DISCOUNT RATESThe following presents the Water Utility’s proportionate share of the City’s total OPEB liability, calculating using thediscount rate of 3.65% and 3.54% for measurement date as of June 30, 2023 and 2022 respectively, as well as what theWater Utility’s total OPEB liability would be if it was calculated using a discount rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:Measurement DateJune 30, 2023Measurement DateJune 30, 20221% Decrease(2.65%)Current DiscountRate(3.65%)1% Increase(4.65%)1% Decrease(2.54%)Current DiscountRate(3.54%)1% Increase(4.54%)Water Utility'sproportionate share of total OPEB liability$3,627$4,265$3,042$4,432$4,043$3,769CHANGE IN TOTAL OPEB LIABILITYFor fiscal year ended June 30, 2024 and 2023, the Water Utility recognized total OPEB expense of $173 and $168respectively. The following table shows the change in the Water Utility’s proportionate share of the City’s total OPEBliability for the year ended June 30, 2024 (measurement date June 30, 2023) and the year ended June 30, 2023(measurement date June 30, 2022):June 30, 2024Total OPEBLiabilityProportion ofthe CityProportion - Reporting date June 30, 2024 (Measurement Date June 30, 2023)$4,265%6.82Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022)4,043%8.89Changes - Increase / (Decrease)222%-2.07June 30, 2023Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022)$4,043%8.89Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021)4,286%8.79Changes - Increase / (Decrease)(243)%0.10137137NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 7.OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEBAt June 30, 2024 and 2023, the Water Utility reported deferred outflows/(inflows) of resources related to OPEB from thefollowing sources:Deferred Outflowsof Resources Deferred Inflows ofResources Difference between expected andactual expense$89$(223)Change of assumptions403(583)Contributions subsequent tomeasurement date118-Total$610$(806)Deferred Outflowsof Resources Deferred Inflows ofResources Difference between expected andactual expense$12$(255)Change of assumptions509(634)Contributions subsequent tomeasurement date123-Total$644$(889)At June 30, 2024 and 2023, the Water Utility reported deferred outflows/(inflows) of resources related to OPEB to berecognized as OPEB expense as follows: Year EndedJune 30Deferred Outflows/(Inflows) ofResources2025$(5)2026132027162028162029(79)Thereafter(275)Total$(314)Year EndedJune 30Deferred Outflows/(Inflows) ofResources2024$(10)2025(10)202662027820288Thereafter(370)Total$(368)138138NOTES TO THE FINANCIAL STATEMENTS: WATER141 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 8.RESTRICTED NET POSITIONPursuant to applicable bond indentures, a reserve for debt service has been established by restricting assets andreserving a portion of net position. Bond indentures for the Water Utility’s revenue and refunding bonds require debtservice reserves that equate to the maximum annual debt service required in future years and bond service reserves ofthree months interest and nine months principal due in the next fiscal year. Variable rate revenue and refunding bondsrequire 110% of the monthly accrued interest to be included in the reserve. Certain issues have no debt service reserverequirements (2009B, 2011A, 2019A and 2022A). See Note 4 for further discussion related to the Water Utility’s debtissuances. Pursuant to the Eleventh Supplemental Resolution, as stated in the Water Revenue Bonds, Issue of 2022A indentures, theFiscal Agent will establish, maintain and hold in trust a separate account designated as the "2022 Water Revenue BondIssue Rebate Account”. All money at any time deposited in the 2022A Water Revenue Bond Issue Rebate Account will beheld by the Fiscal Agent in the restricted account for payment to the United States Treasury. Within 55 days of the end ofeach bond year, the Water Utility will calculate the amount of rebatable arbitrage. The Fiscal Agent will pay to the UnitedStates Treasury, not later than 60 days after the end of the 5th bond year; and each applicable 5th bond year thereafter, anamount equal to at least 90% of the Rebatable Arbitrage calculated as of the end of such bond year; not later than 60 daysafter the payment of all of the 2022A Bonds, an amount equal to 100% of the Rebatable Arbitrage calculated as of the endof such applicable bond year, and any income attributable to the Rebatable Arbitrage (Section 148(f) of the Code andSection 1.148 3 of the Treasury Regulations). During the interim computation period from 12/1/2022 throught 12/1/2023,the excess Arbitrage Rebate Liability in the amount of $673 was computed. As of June 30, 2024, the Water Utility recordedan arbitrage liability related to the 2022 Water Revenue Bonds Series A. See Note 4 for further discussion related to theWater Utility’s debt issuances. In the Annual Valuation Report as of June 30, 2021, CalPERS reported an investment return of 21.3%. These positivereturns contributed to the reduction of the unfunded accrued liability (UAL). The City did not eliminate the budgeted UALpayments during the amendment of the fiscal year 2023-24 budget, but rather redirected those budgeted payments therespective funds' restricted cash and investments held at fiscal agent and restricted fund balance for future UAL costs.See Note 6 for further discussion related to the UAL. 9.CONSTRUCTION COMMITMENTSAs of June 30, 2024, the Water Utility had commitments (encumbrances) of approximately $13,304 with respect toongoing capital projects, of which $12,965 is expected to be funded by bonds, and $339 to be funded by unrestrictedreserves. 139NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 10.LITIGATIONThe Water Utility is a defendant in various lawsuits arising in the normal course of business. Present lawsuits and otherclaims against the Water Utility are incidental to the ordinary course of operations of the Water Utility and are largelycovered by the City’s self-insurance program. In the opinion of management and the City Attorney, such claims andlitigation will not have a materially adverse effect upon the financial position or results of operations of the Water Utility.CITY OF RIVERSIDE V. BLACK & DECKER (U.S.), INC.The Water Utility is a plaintiff in a lawsuit against several entities that either owned or leased a property site in the City ofColton and City of Rialto that is contaminated by perchlorate. The lawsuit was filed March 31, 2009. On May 24, 2018, theState trial court dismissed the action, with prejudice, for failure to join the federal Department of Defense, with instructionsto refile the lawsuit in federal court and include the Department of Defense as a party. The City has appealed suchdismissal, and on May 6, 2020, the appellate court overturned the trial court’s dismissal. The appellate court remanded thecase back to the trial court and the parties are now waiting for the trial court to set a trial date. The City has reached asettlement with two of the defendants, Trojan Fireworks Company and Zambelli, and those defendants have beendismissed from the lawsuit.PONGS V. CITY OF RIVERSIDE (“PONGS I”)On December 16, 2019, a lawsuit entitled Pongs v. City of Riverside (“Pongs I”) was filed against the City challenging theCity’s Water Rate WA-12, “Agricultural Water,” alleging that the City is overcharging customers for service under this ratein violation of Article XIIID, Section 6 of the California Constitution. The plaintiff is seeking that the court invalidate WaterRate WA-12 and refund all to all WA-12 customers monies collected under that rate. A hearing date for the first phase ofthe trial, on liability, has been scheduled for November 17, 2021. This lawsuit has been stayed pending the resolution ofanother lawsuit challenging the City’s Water General Fund Transfer, entitled Simpson v. City of Riverside (Simpson I, asreferenced below).PONGS V. CITY OF RIVERSIDE (“PONGS II”)On December 22, 2022, a lawsuit entitled Pongs v. City of Riverside (“Pongs II”) was filed against the City. This case is areverse validation action filed by Carl Pongs and Richard Moslenko against the City challenging under Proposition 218 theCity’s issuance of bonds in 2022 secured by the water rates. On August 18, 2023, the trial court ruled in favor of the City,and the case is now pending in the Court of Appeal. No hearing date has been set.PONGS V. CITY OF RIVERSIDE (“PONGS III”)On January 26, 2024, a lawsuit entitled Pongs v. City of Riverside (“Pongs III”) was filed against the City. In late 2023, theCity of Riverside (the “City”) adopted Resolution No. 24042 setting new water rates for fiscal years 2023-24 to 2027-28.Pongs III is a reverse validation action challenging the validity of the new rates. Pongs alleges multiple violations of ArticleXIII D (also referred herein as Proposition 218) including, inter alia, illegal transfers of water rate revenue from the City’swater utility into the General Fund, invalid tiered rate structures, and improper spending of water rate revenue oncategories unrelated to the provision of water service. No hearing date has been set.PONGS ET AL. V. CITY OF RIVERSIDE ET AL. (“PONGS IV”)On March 3, 2023, a lawsuit entitled Pongs et al. v. City of Riverside et al. was filed against the City by a water customeras an individual and seeking class action certification, alleging that the City improperly acquired shares in the Gage CanalCompany in breach of the Gage Canal Operating Agreement entered into on June 9, 1965. Plaintiff seeks return of theGage Canal shares to all shareholders improperly divested of shares and that the Court enjoin the City from continuing itscurrent practice to acquire ownership of Gage Canal shares. No trial date has been set in this matter.SIMPSON V. CITY OF RIVERSIDE (“SIMPSON I”)On December 19, 2019, a class action lawsuit entitled Simpson v. City of Riverside was filed against the City alleging thatthe City is overcharging customers for water utility service in violation of Article XIIID, Section 6 of the CaliforniaConstitution, on the grounds that the City is transferring 11.5% of water utility revenues to the City’s general fund. Thetransfer, also known as the “General Fund Transfer,” was approved by voters on June 4, 2013, as a general tax. Theplaintiff is seeking refunds for all customers for monies collected in violation and also that the court set aside the voter’s2013 approval of the General Fund Transfer. The trial was bifurcated into two phases, liability and damages. The Courtissued its ruling on the liability phase on August 17, 2023, finding that the City’s water rates violated Article XIID, Section 6140NOTES TO THE FINANCIAL STATEMENTS: WATER143 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 10.LITIGATION (CONTINUED)of the California Constitution because they were set in an amount sufficient to recover the General Fund Transfer. A trialdate of September 6, 2024 has been set for the second phase of the trial regarding damages.SIMPSON V. CITY OF RIVERSIDE (“SIMPSON II”)On January 26, 2024, a lawsuit entitled Simpson v. City of Riverside (“Simpson II”) was filed against the City. In late 2023,the City of Riverside (the “City”) adopted Resolution No. 24042 setting new water rates for fiscal years 2023-24 to 2027-28.Simpson II is a reverse validation action challenging the validity of the new rates. Pongs alleges multiple violations ofArticle XIII D (also referred herein as Proposition 218) including, inter alia, illegal transfers of water rate revenue from theCity’s water utility into the General Fund, invalid tiered rate structures, and improper spending of water rate revenue oncategories unrelated to the provision of water service. No hearing date has been set. This lawsuit has been stayedpending the resolution of another lawsuit challenging the City’s Water General Fund Transfer, entitled Simpson v. City ofRiverside (Simpson I, as referenced below).CITY OF RIVERSIDE V. 3M COMPANY, ET AL.The Water Utility is a plaintiff in a lawsuit against several entities over contamination of its water supply wells with syntheticper- and polyfluoroalkyl substances (“PFAS”). The lawsuit was filed July 26, 2021, as part of a multidistrict litigationproceeding consolidated before a federal judge in Charleston, South Carolina. No trial date has been set.CITY OF RIVERSIDE V. SHELL OIL COMPANY, ET AL.The Water Utility is a plaintiff in a lawsuit against several entities over contamination of its water supply wells with 1, 2, 3, -Trichloropropane (“TCP”). The lawsuit was filed December 4, 2020, in the superior court in San Francisco. No trial datehas been set. 141NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTSFor the year ended June 30, 2023, the financial statements include the adoption of GASB Statement No. 96, Subscription-Based Information Technology Agreements (SBITA). This Statement defines SBITA as a contract that conveys control ofthe right to use another party’s information technology software, alone or in a combination with tangible capital asset, asspecified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer tothe disclosures below.LEASES PAYABLELeases are financings of the right-to-use an underlying asset and a lessee is required to recognize a lease liability and anintangible lease asset.The Water Utility has consistently maintained 4 leases as Lessee for the use of various pieces of machinery andequipment for the fiscal years ended June 30, 2024 and 2023. The Water Utility is required to make principal and interestpayments through fiscal year 2029. As of June 30, 2024 and 2023, the value of the lease liability were $21 and $14,respectively. The leases had an interest rate of 0.52% to 2.50% and 0.52% for the fiscal years ended June 30, 2024 and2023. The value of the lease assets were $26 and $21 with accumulated amortization of $6 and $10 for the fiscal yearsended June 30, 2024 and 2023, as shown on the Asset Class activities table found below.Amount of Lease Assets byMajor Classes ofUnderlying AssetJune 30, 2024Asset ClassLease AssetValueAccumulatedAmortizationMachinery and equipment$26$(6)Total$26$(6)Amount of Lease Assets byMajor Classes ofUnderlying AssetJune 30, 2023Asset ClassLease AssetValueAccumulatedAmortizationMachinery and equipment$21$(10)Total$21$(10)The following is a summary of changes in leases liability during the fiscal years ended June 30, 2024 and 2023:BalanceAs of6/30/2022AdditionsReclassReductionsBalanceAs of6/30/2023AdditionsReclassReductionsBalanceAs of6/30/2024Due WithinOne YearLease Liability$16$-$-$(4)$12$21$-$(12)$21$5142NOTES TO THE FINANCIAL STATEMENTS: WATER145 WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)As of June 30, 2024, lease liability principal and interest payments consist of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2025$5$1$620264-420274-420284-420294-4Total$21$1$22As of June 30, 2023, lease liability principal and interest payments consist of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2024$5$-$520254-420263-3Total$12$-$12LEASES RECEIVABLELeases are financings of the right-to-use an underlying asset and a lessor is required to recognize a lease receivable and adeferred inflow of resources.The Water Utility had 23 and 22 leases as a Lessor for the use of various pieces of land and buildings for the fiscal yearsended June 30, 2024 and 2023, respectively. At June 30, 2024 and 2023 the terms of these leases range from 3 to 55 and2 to 55 years beginning on the contract commencement date. For the fiscal years ended of June 30, 2024 and 2023, thevalue of the lease receivables were $89,569 and $87,936, with interest rates consistently ranging from 0.52% to 3.35%and 0.52% to 2.81%, respectively. As of June 30, 2024 and 2023, the value of the deferred inflow of resources were$101,497 and $101,990, with recognized lease revenue of $2,928 and $2,841, respectively.As of June 30, 2024, lease receivable principal and interest payments consist of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2025$847$1,700$2,54720268731,6972,57020275701,6962,26620282951,7102,00520293101,7142,0242030-20341,3278,5259,8522035-20392,0497,99010,0392040-20447,7987,20815,0062045-20499,3696,38415,7532050-205411,2365,44316,6792055-205913,4674,34017,8072060-206415,7953,00718,8022065-206917,5021,49718,9992070-20748,1312348,365Total$89,569$53,145$142,714143NOTES TO THE FINANCIAL STATEMENTS: WATER WATER UTILITY:NOTES TO THE FINANCIAL STATEMENTS 11.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)LEASES RECEIVABLE (CONTINUED)As of June 30, 2023, lease receivable principal and interest payments consist of the following:Fiscal YearPrincipalPaymentsInterestPaymentsTotalPayments2024$763$1,618$2,38120257821,6152,39720267971,6152,41220274911,6162,10720282141,6321,8462029-20339248,2219,1452034-20387587,8808,6382039-20436,0027,26713,2692044-20488,8126,54715,3592049-205310,9705,64416,6142054-205812,8584,57817,4362059-206315,4773,28718,7642064-206817,4301,81119,2412069-207311,65840812,066Total$87,936$53,739$141,675SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS PAYABLEThe Water Utility has consistently maintained 2 subscription-based information technology arrangements (SBITA) for theuse of various software for the fiscal years ended June 30, 2024 and 2023. The Water Utility is required to make principaland interest payments through fiscal year 2025. An initial lease liability was recorded in the amount of $32. At June 30,2024 and 2023, the value of the subscription liability was $2 and $17 with a consistent interest rate of 0.52%, respectively.As of June 30, 2024 and 2023, the value of the subscription assets were $33 and $32 with accumulated amortization of$25 and $15.As of June 30, 2024 and 2023, the Asset Class activities tables were as follows: Amount of SBITA Assets byMajor Classes ofUnderlying AssetJune 30, 2024Asset ClassSBITA AssetValueAccumulatedAmortizationSoftware$33$(25)Total$33$(25)Amount of SBITA Assets byMajor Classes ofUnderlying AssetJune 30, 2023Asset ClassSBITA AssetValueAccumulatedAmortizationSoftware$32$(15)Total$32$(15)144NOTES TO THE FINANCIAL STATEMENTS: WATER147

11.LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS(CONTINUED)SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS PAYABLE (CONTINUED)The following is a summary of changes in SBITA liability during the fiscal years ended June 30, 2024 and 2023:BalanceAs of6/30/2022AdditionsReclassReductionsBalanceAs of6/30/2023AdditionsReclassReductionsBalanceAs of6/30/2024Due WithinOne YearSBITA Liability$32$-$-$(15)$17$-$-$(15)$2$2As of June 30, 2024, SBITA liability principal and interest payments consist of the following: Fiscal YearPrincipalInterestTotalPayments2025$2$-$2Total$2$-$2As of June 30, 2023, SBITA liability principal and interest payments consist of the following:Fiscal YearPrincipalInterestTotalPayments2024$15$-$1520252-2Total$17$-$17 12.PRIOR PERIOD ADJUSTMENTA prior period adjustment was made to decrease the Water Utility’s, including Water Conservation Programs, net position.The Water Utility has been restated to reflect an adjustment to two GASB 87 related leases totaling $2,515, which wereimplemented in fiscal year 2022. The two GASB 87 lease adjustments affected the lease receivable, deferred inflows -Lease related items, Long-term obligations, and other assets for the Water Utility, resulting in a net decrease in netposition of $2,515. The restatement of beginning net position is as follows:June 30, 2022as PreviouslyReported Error CorrectionJune 30, 2022as RestatedNet Position$322,304$(2,515)$319,789145NOTES TO THE FINANCIAL STATEMENTS: WATER Reporting period 2024 2023 2022 2021 2020Measurement period 2023 2022 2021 2020 2019Water Utility's Proportion of the Net Pension Liability 9.33% 9.76% 9.93% 10.16% 10.90%Water Utility's Proportionate Share of the Net Pension Liability 14,455$ 12,854$ (8,809)$ 12,203$ 31,840$ Water Utility's Covered Payroll 13,258$ 12,694$ 13,034$ 13,364$ 14,044$ Water Utility's Proportionate Share of the Net Pension Liability as a Percentage of Covered Payroll 109.03% 101.26% -67.59% 91.31% 226.72%Water Utility's Proportionate Share of the Fiduciary Net Position as a Percentage of the Water Utility's Total Pension Liability 90.73% 91.80% 105.72% 91.95% 79.57%Notes to Schedule:Benefit Changes:There were no changes in benefits.Changes in Assumptions:From fiscal year June 30, 2015 to June 30, 2016:GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension planinvestment expense but without reduction for pension plan administrative expense. The discount rate of 7.50% used forthe June 30, 2014 measurement date was net of administrative expenses. The discount rate of 7.65% used for theJune 30, 2015 measurement date is without reduction of pension plan administrative expense.From fiscal year June 30, 2016 to June 30, 2017:There were no changes in assumptions.From fiscal year June 30, 2017 to June 30, 2018:The discount rate was reduced from 7.65% to 7.15%.From fiscal year June 30, 2018 to June 30, 2022:There were no significant changes in assumptions.From fiscal year June 30, 2022 to June 30, 2023:The discount rate and long-term rate of return decreased from 7.15% to 6.90% and the inflation rate decreased from2.50% to 2.30%.From fiscal year June 30, 2023 to June 30, 2024:There were no significant changes in assumptions. (amounts expressed in thousands)WATER UTILITYSCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITYAS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS (1) 146REQUIRED SUPPLEMENTARY INFORMATION: WATER149
Reporting period 2019 2018 2017 2016 2015Fiscal Year Ended 2018 2017 2016 2015 2014Water Utility's Proportion of the Net Pension Liability 11.03% 11.44% 11.14% 11.59% 11.30%Water Utility's Proportionate Share of the Net Pension Liability 30,737$ 38,880$ 34,465$ 28,257$ 26,032$ Water Utility's Covered Payroll 13,455$ 13,457$ 13,197$ 12,853$ 12,425$ Water Utility's Proportionate Share of the Net Pension Liability as a Percentage of Covered Payroll 228.44% 288.93% 261.15% 219.85% 209.52%Water Utility's Proportionate Share of the Fiduciary Net Position as a Percentage of the Water Utility's Total Pension Liability 79.64% 75.23% 75.47% 79.93% 80.86%Notes to Schedule:Benefit Changes:There were no changes in benefits.Changes in Assumptions:From fiscal year June 30, 2015 to June 30, 2016:GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension planinvestment expense but without reduction for pension plan administrative expense. The discount rate of 7.50% used forthe June 30, 2014 measurement date was net of administrative expenses. The discount rate of 7.65% used for theJune 30, 2015 measurement date is without reduction of pension plan administrative expense.From fiscal year June 30, 2016 to June 30, 2017:There were no changes in assumptions.From fiscal year June 30, 2017 to June 30, 2018:The discount rate was reduced from 7.65% to 7.15%.From fiscal year June 30, 2018 to June 30, 2022:There were no significant changes in assumptions.From fiscal year June 30, 2022 to June 30, 2023:The discount rate and long-term rate of return decreased from 7.15% to 6.90% and the inflation rate decreased from2.50% to 2.30%.From fiscal year June 30, 2023 to June 30, 2024:There were no significant changes in assumptions. (amounts expressed in thousands)Water UtilitySCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY (CONTINUED)AS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS (1) 147REQUIRED SUPPLEMENTARY INFORMATION: WATER
WATER UTILITYSCHEDULE OF CONTRIBUTIONSAS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS2024 2023 2022 2021 2020Contractually Required Contribution (Actuarially Determined) 1,981$ 2,718$ 2,667$ 2,610$ 3,952$ Contributions in Relation to the Actuarially Determined Contributions (1,981) (2,718) (2,667) (2,610) (24,313) Contribution Deficiency (Excess) -$ -$ -$ -$ (20,361)$ Covered Payroll 4,186$ 13,258$ 12,694$ 13,034$ 13,364$ Contributions as a Percentage of Covered Payroll 47.32% 20.50% 21.01% 20.02% 29.58%Notes to Schedule:Valuation Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017Methods and Assumptions Used to Determine Contribution Rates:Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry AgeAmortization Method (1) (1) (1) (1) (1)Asset Valuation Method Fair Value Fair Value Fair Value Fair Value Fair ValueInflation 2.300% 2.300% 2.500% 2.500% 2.625%Salary Increases (2) (2) (2) (2) (2)Investment Rate of Return 6.90% (3) 6.90% (3) 7.00% (3) 7.00% (3) 7.25% (3)Retirement Age (4) (4) (4) (4) (4)Mortality (5) (5) (5) (5) (5)(1) Level percentage of payroll, closed(2) Depending on age, service, and type of employment(3) Net of pension plan investment expense, including inflation(4) Classic: 50-67 and PEPRA: 52-67(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study adopted by the CalPERS Board. (amounts expressed in thousands)
148REQUIRED SUPPLEMENTARY INFORMATION: WATER151
WATER UTILITYSCHEDULE OF CONTRIBUTIONSAS OF JUNE 30, FOR THE LAST TEN FISCAL YEARS2019 2018 2017 2016 2015Contractually Required Contribution (Actuarially Determined) 3,758$ 3,304$ 3,083$ 2,771$ 2,441$ Contributions in Relation to the Actuarially Determined Contributions (3,758) (3,304) (3,486) (3,277) (3,013) Contribution Deficiency (Excess) -$ -$ (403)$ (506)$ (572)$ Covered Payroll 14,044$ 13,455$ 13,457$ 13,197$ 12,853$ Contributions as a Percentage of Covered Payroll 26.76% 24.56% 22.91% 21.00% 18.99%Notes to Schedule:Valuation Date 6/30/2016 6/30/2015 6/30/2014 6/30/2013 6/30/2012Methods and Assumptions Used to Determine Contribution Rates:Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry AgeAmortization Method (1) (1) (1) (1) (1)Asset Valuation Method Fair Value Fair Value Fair Value Fair Value 15 YearSmoothedMarket MethodInflation 2.75% 2.75% 2.75% 2.75% 2.75%Salary Increases (2) (2) (2) (2) (2)Investment Rate of Return 7.375% (3) 7.50% (3) 7.50% (3) 7.50% (3) 7.50% (3)Retirement Age (4) (4) (4) (4) (4)Mortality (5) (5) (5) (5) (5)(1) Level percentage of payroll, closed(2) Depending on age, service, and type of employment(3) Net of pension plan investment expense, including inflation(4) Classic: 50-67 and PEPRA: 52-67(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study adopted by the CalPERS Board. (amounts expressed in thousands)
149REQUIRED SUPPLEMENTARY INFORMATION: WATER
Reporting period 2024 2023 2022 2021 2020 2019 2018Measurement period 2023 2022 2021 2020 2019 2018 2017Water Utility's Proportion of the Net OPEB Liability 6.82% 8.89% 8.79% 8.70% 8.76% 9.19% 9.30%Water Utility's Proportionate Share of the Net OPEB Liability 4,265$ 4,043$ 4,286$ 4,550$ 4,382$ 3,524$ 3,410$ Water Utility's Covered Payroll 14,265$ 18,065$ 17,342$ 16,665$ 16,291$ 15,702$ 15,890$ Water Utility's Proportionate Share of the Net OPEB Liability as a Percentage of Covered Payroll 29.90% 22.38% 24.71% 27.30% 26.90% 22.44% 21.46%(1) Historical information is required only for the measurement periods for which GASB 75 is applicable. Fiscal Year 2018 was the first year of implementation. Future years' information will be displayed up to 10 years as information becomes available.Notes to Schedule:Changes in assumptions: For the measurement period ending June 30, 2023, the discount rate was changed from 3.54 percent to 3.65 percent. There are no asset accumulated in a trust that meets the criteria of GASB codification P22.101 or P52.101 to pay related benefits for the OPEB plan.

WATER UTILITYSCHEDULE OF CHANGES IN TOTAL OPEB LIABILITY AND RELATED RATIOS(amounts expressed in thousands)AS OF JUNE 30, FOR THE LAST SEVEN FISCAL YEARS (1) 150REQUIRED SUPPLEMENTARY INFORMATION: WATER153
WATER UTILITYKEY HISTORICAL OPERATING DATAFiscal Year2023/242022/232021/222020/212019/20WATER SUPPLY (ACRE FEET)Potable water production159,86360,18568,05472,21564,827Percentage pumped (%)2100100100100100System peak day (gallons)382,500,00081,800,00082,700,00091,900,00089,600,000WATER USENumber of meters as of year-end:Residential60,04159,90759,87659,78259,598Commercial/Industrial6,1706,1756,1536,0806,068Other359359343336365Total66,57066,44166,37266,19866,031CCF* sales:Residential12,975,99113,078,24215,362,90816,149,35714,610,481Commercial/Industrial48,834,2979,003,45710,245,37710,069,1769,126,132Other4 733,429764,265870,928835,300787,119Subtotal22,543,71722,845,96426,479,21327,053,83324,523,732Wholesale467,726821,502366,3701,571,5491,002,289Total23,011,44323,667,46626,845,58328,625,38225,526,021*(CCF equals 100 cubic feet)WATER FACTSAverage annual CCFper residential customer216218257270245Average price ($/CCF)per residential customer$3.54$3.38$2.98$2.77$2.67Debt service coverage ratio (DSC)5, 6, 7, 8, 91.981.952.232.251.80Employees101651651641651651 Water pumping figures have been adjusted to include retail and wholesale potable water production. Excludes wheeling.2 No purchased water.3 System peak day has been adjusted to reflect production for retail customers. 4 Changes in fiscal year 2019/20 reflect reclassification of certain Commercial/Industrial accounts and Other accounts in connection with current WaterRate Plan.5 Interest expense used to calculate DSC is net of federal subsidy on Build America Bonds.6 Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of $2,483, $(471), $(4,891), $(1,107), and $1,046 for fiscalyears 2023/24 through 2019/20, respectively.7 Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $173, $168,$210, $73, and $197 for fiscal years 2023/24 through 2019/20, respectively. 8 Includes GASB 87 Leases net revenue adjustments of $3,023, $2,957, and $708 for fiscal years 2023/24 through 2021/22, respectively.9 Changes in fiscal year 2022/23 reflect reclassifications of certain long-term obligations and related accounts in connection with GASB 87 Leases.10 Approved positions. 151KEY HISTORICAL OPERATING DATA: WATER

SOURCE OF REVENUE
Residential Sales 49¢
Commercial Sales 26¢
Other Revenue 15¢
Investment Income 8¢
Other Sales 2¢

DISTRIBUTION OF REVENUE
Operations and Maintenance 52¢
Debt Service 23¢
Additions & Replacements to the System 8¢
Transfers to the City's General Fund* 8¢
Additional Reserves 8¢
Water Conservation 1¢

WATER RESOURCES
San Bernardino Basin Wells 67%
Riverside Basin Wells 33%
Purchased Water 0%Eastern MWDWestern MWDRiverside Public Utilities$0$20$40$60$80$100$12093% Higher 82% Higher $61 *Based on transfer of 11.5% of fiscal year 2022/2023 gross operating revenues, including adjustments. $118 $111 KEY HISTORICAL OPERATING DATA: WATER155 66,03166,19866,37266,44166,57020202021202220232024Number of Meters At Year End$69.7$80.3$80.1$78.7$81.320202021202220232024Total Operating Revenue (In Millions)64,82772,21568,05460,18559,86320202021202220232024Potable Water Production (In Acre Feet)89.691.982.781.882.520202021202220232024Peak Day Demand (In Millions of Gallons) $6.5$7.0$7.7$8.2$8.120202021202220232024General Fund Transfer (In Millions) KEY HISTORICAL OPERATING DATA: WATER
W A TE R F A C TS A N D SYSTE M D A TAEstablished................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................1913Service Area Population................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................316,690Service Area Size (square miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................74.24System Data:Smallest Pipeline................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................2.0"Largest Pipeline................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................72.0"Miles of Pipeline................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................994Number of Domestic Wells................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................51Number of Active Reservoirs................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................16Total Reservoir Capacity (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................108,500,000Number of Treatment Plants................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................6Number of Treatment Vessels................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................84Miles of Canal................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................14Number of Fire Hydrants................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................8,052Daily Average Production (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................57,050,0002023-2024 Peak Day (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................82,500,00006/24/24, 95 degreesHistorical Peak (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................118,782,00008/09/05, 99 degreesBond Ratings:Fitch Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA+Moody's................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................Aa2S&P Global Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA+ 154KEY HISTORICAL OPERATING DATA: WATER157

RIVERSIDE PUBLIC UTILITIES3750 University Avenue, 5th FloorRiverside, CA 92501(951) 826-2135RiversidePublicUtilities.com