2023 RPU — Financial Performance and Budget Committee, January 10, 2024

2023

FINANCIAL
REPORT

RIVERSIDE PUBLIC UTILITIES

SERVICE AREA POPULATION
313,676

RECORD PEAK DEMAND
Energy:

Water:

TOTAL OPERATING REVENUE
Energy:

Water:

CUSTOMERS
Energy:

Water:

CREDIT RATING
Energy:

Water:

OVERVIEW
Riverside 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
City Council representatives for final determination.

AA- Fitch
AA- S&P Global
AA+ Fitch
AA+ S&P Global
Aa2 Moody’s
648 megawatts
9/7/2022
365 acre feet
119 million gallons
8/9/2005
$418.9 million
$78.7 million
112,751
66,441
RiversidePublicUtilities.com

OUR CORE
VALUES
Safety
Honesty and Integrity
Teamwork
Professionalism
Quality Service
Creativity and Innovation
Community Involvement
Environmental
Stewardship
Inclusiveness and Mutual
Respect

OUR VISION
Our 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 MISSION
The City of Riverside Public Utilities Department is
committed to the highest quality water and electric
services at the lowest possible rates to benefit the
community.

RELIABILITY & RESILIENCY
Taking care of our infrastructure,
so that it remains safe, and
efficient.

AFFORDABILITY
Thriving financially while
balancing affordable rates for
our customers.

SUSTAINABILITY
Ensuring adequate power
and water supply in the most
environmentally responsible
manner.

CUSTOMER EXPERIENCE
Continuing to provide reliable
customer-centered service
every day.

OPERATIONAL EXCELLENCE
Implementing new technologies
that will enhance the customer
experience and ensure
the tradition of operational
excellence.

STRONG WORKFORCE
Developing and supporting
a workforce that is safe,
prepared and engaged.

OUR
FOCUS
AREAS
Arts, Culture
and Recreation
Community
Well-Being
Economic
Opportunity
Environmental
Stewardship
High Performing
Government
Infrastructure,
Mobility and
Connectivity

ENVISION

RIVERSIDE
2025Community
Trust
Sustainability
and Resiliency
Equity Innovation
Fiscal
Responsibility

CROSS-CUTTING THREADS

STRATEGIC PRIORITIES
GOALS

ACTIONS

METRICS
Community Trust – Riverside is transparent and makes decisions based on sound policy, inclusive community engagement, involvement of City Boards & Commissions, and timely and reliable information. Activities and actions by the City serve the public interest, benefit the City’s diverse 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 community has equal access to share in the benefits of community progress.

Fiscal Responsibility – Riverside is a prudent steward of public funds and ensures responsible management of the City’s financial resources while providing quality public services to all.

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 grow during good and difficult times alike.

CROSS-CUTTING THREADS
Infrastructure, Mobility
& Connectivity
Ensure safe, reliable infrastructure that benefits the
community 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
Stewardship
Champion 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 4.3
Implement 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-Being
Ensure 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. 1 23
456
7 CITY COUNCIL
Patricia Lock Dawson
Mayor
Erin Edwards
Ward 1
Clarissa Cervantes
Ward 2
Ronaldo Fierro
Ward 3
Chuck Conder
Ward 4
Gaby Plascencia
Ward 5
Jim Perry
Ward 6
Steve Hemenway
Ward 7

BOARD OF PUBLIC UTILITIES
Gil Oceguera
(Board Chair)
Ward 7
Rebeccah A. Goldware
(Board Vice Chair)
Ward 2
David M. Crohn
Ward 1
Nipunjeet Gujral
Ward 3
Gary Montgomery
Ward 4
Nancy E. Melendez
Ward 5
Rosemary Heru
Ward 6
Peter Wohlgemuth
Citywide / Ward 1
Brian D. Siana
Citywide / Ward 2

EXECUTIVE MANAGEMENT
Mike Futrell
City Manager
Rafael Guzman
Assistant City Manager
Todd Corbin
Utilities General Manager
Daniel E. Garcia
Utilities Deputy General Manager
Carlie Myers
Utilities Assistant General Manager
Business Systems and Customer Service

Daniel Honeyfield
Utilities Assistant General Manager
Energy Delivery
David A. Garcia
Utilities Assistant General Manager
Water Delivery

TABLE OF CONTENTS
Overview
Our Mission
Values and Goals
Executive Management, City Council and Board of Public Utilities

OUR ELECTRIC
Independent Auditors’ Report 9
Management’s Discussion and Analysis 12
Financial Statements
Statements of Net Position 30
Statements of Revenues, Expenses and Changes in Net Position 32 Statements of Cash Flows 33
Notes to the Financial Statements 35
Key Historical Operating Data 76

OUR WATER
Independent Auditors’ Report 83
Management’s Discussion and Analysis 87
Financial Statements
Statements of Net Position 98
Statements of Revenues, Expenses and Changes in Net Position 100 Statements of Cash Flows 101
Notes to the Financial Statements 103
Key Historical Operating Data 132

ELECTRIC
OUR

RIVERSIDE PUBLIC UTILITIES
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ELECTRIC UTILITY:

MANAGEMENT'S DISCUSSION AND ANALYSIS
As management of Riverside Public Utilities, a department of the City of Riverside (the City), we offer the readers this narrative overview and analysis of the 2022/23 financial report for the periods ended June 30, 2023 and 2022 for Riverside’s Electric Utility (Electric Utility), an enterprise fund of the City. We encourage readers to consider the information presented here in conjunction with additional information furnished in our financial statements, which begin on page 30 of this report. All amounts, unless otherwise indicated, are expressed in thousands of dollars.

FINANCIAL HIGHLIGHTS
 Governmental Accounting Standards Board No. 96, Subscription-Based Information Technology Arrangements (GASB 96) - For the year ended June 30, 2023, the financial statements include the adoption of GASB Statement No. 96, Subscription-Based Information Technology Arrangements (SBITA). This Statement defines SBITA as a contract that conveys control of the right to use another party's information technology software, alone or in a combination with tangible capital assets, as specified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer to Notes 1, 3, and 14 in the accompanying financial statements.  Retail sales, net of uncollectibles/recovery were $347,016 and $338,558 for years ended June 30, 2023 and 2022, respectively. The increase in sales was primarily due to rate plan increases, as well as decreased uncollectibles.  Operating expense related to production and purchased power increased by $19,319 primarily due to a combination of exceptionally elevated winter natural gas prices and elevated power prices, along with global market disturbances.  Operating expense reflects a non-cash pension accounting standard adjustment, which will continue to fluctuate based on yearly actuarial information provided by the California Public Employees' Retirement System. The adjustment was $(1,308) and $(16,425) at June 30, 2023 and 2022, respectively.  Utility plant assets decreased by $10,906 primarily due to an increase in current year depreciation, offset by additions and improvements to the Electric distribution infrastructure system to improve service and reliability to the Electric Utility’s customers.
 Investment income on investments increased by $16,282 due to a fair market value adjustment of investments and a higher overall interest rate in the current fiscal year.

OVERVIEW OF THE FINANCIAL STATEMENTS
This discussion and analysis is intended to serve as an introduction to the Electric Utility’s financial statements. The Electric Utility is a department of the City, and its activities are recorded in a separate enterprise fund. These financial statements include only the activities for the Electric Utility and provide comparative information for the last two fiscal years. 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 the financial statements. In addition, this report also contains other supplementary information to provide the reader additional information 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 the Electric Utility’s financial health.

The Statements of Net Position present information on all of the Electric Utility’s assets, liabilities, deferred inflows and outflows of resources and net position. The Statements of Net Position provide information about the nature and amount of the Electric Utility’s resources and obligations at a specific point in time.

The Statements of Revenues, Expenses and Changes in Net Position report all of the Electric Utility’s revenues and expenses for the periods shown.

The Statements of Cash Flows 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 and capital additions and improvements.

The Notes to the Financial Statements provide additional information that is essential to a full understanding of the data provided in the financial statements. The Notes to the Financial Statements can be found on pages 35 to 75 of this report. 12 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
ELECTRIC UTILITY:

MANAGEMENT'S DISCUSSION AND ANALYSIS

ELECTRIC UTILITY FINANCIAL ANALYSIS

CONDENSED STATEMENTS OF NET POSITION
2023 2022 2021
Current and other assets $ 454,579 $ 501,765 $ 483,635
Capital assets 785,321 796,227 797,902
Deferred outflows of resources 45,624 24,943 42,782
Total assets and deferred outflows of resources 1,285,524 1,322,935 1,324,319 Long-term debt outstanding 590,602 615,834 639,791
Other liabilities 174,333 148,059 184,848
Deferred inflows of resources 17,237 53,479 2,307
Total liabilities and deferred inflows of resources 782,172 817,372 826,946 Net investment in capital assets 254,990 246,698 237,968 Restricted 74,163 64,422 57,884
Unrestricted 174,199 194,443 201,521
Total net position $ 503,352 $ 505,563 $ 497,373

ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
2023 compared to 2022 The Electric Utility’s 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, primarily due to a decrease of $12,833 in accounts receivable primarily due to renewed collection efforts post COVID-19, the decrease of $26,341 in unrestricted cash and cash equivalents primarily due to the funding of capital projects, and the transition of the net pension asset created as a result of GASB 68 to a net pension liability. The net decrease was offset by an increase of $10,388 in restricted cash and cash equivalents held by the City and ongoing operating expenditures.
 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 and reliability to the Electric Utility’s customers. Additional capital asset information can be found in the “Capital Assets and Debt Administration” section.
 Deferred outflows of resources increased by $20,681 primarily due to an increase of $25,763 in deferred outflows related to pension, offset by the change of $4,353 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-term Obligation. 2022 compared to 2021 Total assets and deferred outflows of resources were $1,322,935, a net decrease of $1,384 (0.1%). Current and other assets had a net increase of $18,130, primarily due to an increase of $6,639 in restricted cash and cash equivalents held by the City, an increase of $6,308 in accounts receivable primarily due to COVID-19 impacts, the net pension asset created as a result of GASB 68, and the long-term and short-term receivables created as a result of GASB 87. The net increase was offset by a decrease of $13,122 in unrestricted cash and cash equivalents, and the use of $7,473 in restricted bond proceeds to fund capital projects. Capital assets decreased by $1,675 primarily due to current year depreciation of $32,378, offset by an increase of $30,212 in additions and improvements to the Electric distribution infrastructure system to improve service and reliability to the Electric Utility’s customers, as well as $628 in right-to-use lease assets offset by amortization of $137. Deferred outflows of resources decreased by $17,839 primarily due to a decrease in the fair market value of interest rate swaps. 13 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC13
ELECTRIC UTILITY:

MANAGEMENT'S DISCUSSION AND ANALYSIS

LIABILITIES AND DEFERRED INFLOWS OF RESOURCES
2023 compared to 2022 The Electric Utility’s 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 bond principal payments. Additional debt information can be found in the “Capital Assets and Debt Administration” section.  Other liabilities increased by $26,274 primarily due to an increase of $38,748 in net pension liability. The increase was offset by decreases of $4,808 due to the change in the fair market value of interest rate swaps, as well as $4,437 in nuclear decommissioning liability, $2,687 in accounts payable, and $1,098 in unearned revenue. Additional nuclear decommissioning information can be found in Notes 10 and 13.  Deferred inflows of resources decreased by $36,242 primarily due to pension related adjustments, which included the changes in assumptions, the differences between expected and actual experience and the change in projected versus actual earnings on pension plan investments as determined by the plan actuary. The decrease was offset by an increase in the deferred inflows related to the leases. Additional information can be found in Note 14. 2022 compared to 2021 Total liabilities and deferred inflows of resources were $817,372, a decrease of $9,574 (1.2%).

Long-term debt outstanding decreased by $23,957 primarily due to revenue bond and pension obligation bond principal payments. Other liabilities decreased by $36,789 primarily due to a decrease of $39,233 in net pension liability, and a decrease of $11,063 due to a decrease in the fair market value of interest rate swaps. Deferred inflows of resources increased by $51,172 primarily due to pension related adjustments, which included the changes in assumptions, the differences between expected and actual experience, and the change in projected versus actual earnings on pension plan investments as determined by the plan actuary, as well as the creation of the deferred inflows related to leases as a result of GASB 87.

NET POSITION
2023 compared to 2022 The Electric Utility’s net position, which represents the difference between the Electric Utility’s total assets and deferred outflows of resources less total liabilities and deferred inflows of resources, totaled $503,352, a decrease of $2,211 (0.4%). The following represents the changes in components of net position:
 The largest portion of the Electric Utility’s total net position, $254,990 (50.7%), an increase of $8,292, reflects its 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 $74,163 (14.7%), an increase of $9,741, and represents resources that are 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 $174,199 ( 34.6%), a decrease of $20,244 from prior year, which is primarily attributable to a decrease in operating income mainly as a result of higher power costs and the use of reserves 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 to customers and creditors.
2022 compared to 2021 Total net position increased by $8,190 (1.7%), to a total of $505,563. The largest portion of the Electric Utility's total net position, $246,698, reflects its investment in capital assets less any related outstanding debt used to acquire those assets. The restricted portion of net position totaled $64,422 and represents resources that are 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 $194,443, a decrease of $7,078 from prior year, which is primarily attributable to a reduction of $10,826 in investment income, offset by an increase of $2,608 in capital contributions. Unrestricted net position may be used to meet the Electric Utility's ongoing operational needs and obligations to customers and creditors.
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CONDENSED STATEMENTS OF CHANGES IN NET POSITION
2023 2022 2021
Revenues:

Retail sales, net $ 347,016 $ 338,558 $ 318,373
Wholesale sales 2,043 89 27
Transmission revenue 35,233 32,245 32,316
Investment income 5,952 - 496
Other revenues 30,747 25,852 18,995
Public Benefit Programs 10,222 8,978 9,252
Capital contributions 9,854 7,667 5,059
Total revenues 441,067 413,389 384,518
Expenses:

Production and purchased power 195,914 176,595 163,908
Transmission 68,052 65,996 59,770
Distribution 68,057 39,738 70,479
Public Benefit Programs 6,751 5,467 6,419
Depreciation 38,189 36,718 35,654
Amortization 214 134 -
Loss on Investments - 10,330 -
Interest expenses and fiscal charges 23,775 25,037 25,901 Total expenses 400,952 360,015 362,131
Transfers to the City's general fund (42,326) (39,436) (39,899) Extraordinary item - (5,748) -
Changes in net position (2,211) 8,190 (17,512)
Net position, July 1, as previously reported 505,563 497,373 514,885 Net position, June 30 $ 503,352 $ 505,563 $ 497,373
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REVENUES BY SOURCES
2023 compared to 2022 The Electric Utility’s total revenues of $441,067 increased by $27,678 (6.7%) with changes in the following:
 Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $347,016, a $8,458 (2.5%) increase. Retail sales continue to be the primary revenue source for the Electric Utility. The increase in sales 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 requirements and 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-trade auction proceeds.
2022 compared to 2021 The Electric Utility’s total revenues of $413,389 increased by $28,871 (7.5%) with changes in the following:
 Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $338,558, a $20,185 (6.3%) increase. Retail sales continue to be the primary revenue source for the Electric Utility. The increase in sales was primarily due to rate plan increases, as well as decreased uncollectibles.  Other revenues of $25,852 increased by $6,857 ( 36.1%) primarily due to an increase in cap-and-trade auction proceeds.
 Capital contributions of $7,667 increased by $2,608 ( 51.6%) mainly due to an increase in donated underground electrical conduit.
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EXPENSES BY SOURCES
2023 compared to 2022 The Electric Utility’s total expenses, excluding general fund transfer, were $400,952, an increase of $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 combination of 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 California Edison's high voltage rate and an increase in the transmission access charge from the California Independent System Operator (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 in administrative and general operating expenses.
 Depreciation expense of $38,189 increased by $1,471 (4.0%), reflecting the completion of capital projects and their current year depreciation.
2022 compared to 2021 The Electric Utility’s total expenses, excluding general fund transfer, were $360,015, a decrease of $2,116 (0.6%). The decrease was primarily due to the following:
 Production and purchased power expenses of $176,595 increased by $12,687 (7.7%) primarily due to an increase in the cost of energy.
 Transmission expenses of $65,996 increased by $6,226 (10.4%) mainly due to an increase in Southern California Edison's high voltage rate and an increase in the transmission access charge from the California Independent System Operator (CAISO).
 Distribution expenses of $39,738 decreased by $30,741 (43.6%) mainly due to a non-cash pension adjustment of $(16,425) compared to prior year non-cash pension adjustment of $9,682 as a result of pension accounting standards. 17 ELECTRIC UTILITY:

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 Depreciation expense of $36,718 increased by $1,064 (3.0%), reflecting the completion of capital projects and their current year depreciation.
 Loss on investments of $10,330 occurred due to a fair market value adjustment of investments and a lower overall interest rate in the current fiscal year.

TRANSFERS
Pursuant to the City of Riverside Charter, the Electric Utility may transfer up to 11.5 percent of prior year’s gross operating revenues, including adjustments, to the City’s general fund. The City uses these funds to help provide needed public services to the residents of the City, including police, fire, parks, libraries and other benefits. The Electric Utility transferred $42,326 and $39,436 for 2023 and 2022, respectively, based on the gross operating revenue provisions in the City’s Charter. Additional information can be found in Note 12 of the accompanying financial statements.

CAPITAL ASSETS AND DEBT ADMINISTRATION

CAPITAL ASSETS
The Electric Utility’s investment in capital assets includes investments in production, transmission, and distribution related facilities, 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:
2023 2022 2021
Utility plant
Production $ 136,413 $ 148,896 $ 157,370
Transmission 30,039 28,044 27,678
Distribution 408,103 407,181 404,352
General 63,030 65,032 63,689
Intangibles 8,032 10,166 8,639
Land 56,386 53,042 53,042
Intangibles, non-amortizable 10,651 10,651 10,651
Construction in progress 72,262 72,724 72,481
Total utility plant 784,916 795,736 797,902
Lease assets 1
Building 199 286 -
Machinery and equipment 156 205 -
Subscription-based information technology arrangements 50 - - Total lease assets 405 491 -
Total capital assets $ 785,321 $ 796,227 $ 797,902
1 GASB 87 Leases was implemented effective July 1, 2021. GASB 96 Subscription-Based Information Technology Arrangements (SBITA) was implemented effective July 1, 2022. For additional information, refer to Notes 1 and 14. 2023 compared to 2022 The Electric Utility’s 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 significant capital projects:
 $8,801 in recurring expenditures such as transformer replacements, cable replacements, and the Riverside Transmission Reliability Project for additional generation import capability for a second point of interconnection with the 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. 18 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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2022 compared to 2021 Investment in capital assets, net of accumulated depreciation, was $796,227, a decrease of $1,675 ( 0.2%). The decrease resulted primarily from the current year depreciation offset by $13,970 in recurring expenditures such as transformer replacements, improvements to the city-wide communications network, distribution line extensions, major overhead/underground conversions, and the Riverside Transmission Reliability Project, $6,567 in underground improvements, $4,289 in system automation improvements, $2,222 in donated underground electrical conduit, donated street lighting, and donated land rights and easement, and $491 in lease assets as a result of the implementation of GASB 87.

Additional information regarding capital assets can be found in Notes 3 and 14 of the accompanying financial statements.

DEBT ADMINISTRATION
The following table summarizes outstanding long-term debt as of June 30:
2023 2022 2021
Revenue bonds $ 507,370 $ 524,130 $ 540,165
Unamortized premium 42,457 45,055 47,657
Financed purchases - 364 909
Pension obligation bonds 63,408 67,641 70,951
Less: Current portion of outstanding debt (22,633) (21,356) (19,891) Total long-term debt $ 590,602 $ 615,834 $ 639,791
The Electric Utility’s bond indentures require the Electric Utility to maintain a minimum debt service coverage ratio, as defined by the bond covenants, of 1.10. The Electric Utility’s debt service coverage ratio was 2.01, 2.03, and 1.99 at June 30, 2023, 2022 and 2021, respectively. This debt is backed by the revenues of the Electric Utility. Debt service coverage ratio decreased at June 30, 2023 due to decreased net revenues compared to prior year along with an increase to principal payments on debt service. For additional information, see Note 4 of the accompanying financial statements and Key Historical Operating Data section.
2023 compared to 2022 The Electric Utility’s long-term debt decreased by $25,232 ( 4.1%) to $590,602 as a result of current year principal payments and amortization of bond premiums. 2022 compared to 2021 Long-term debt decreased by $23,957 (3.7%) to $615,834 as a result of current year principal payments and amortization of bond premiums.

Additional information on the Electric Utility’s long-term debt can be found in Note 4 of the accompanying financial statements.

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 meet California's increasing environmental regulations with an emphasis on renewable energy resources, stable financial performance and strong liquidity levels.

REGULATORY, LEGISLATIVE FACTORS, AND RATES
Utilities are faced with ongoing regulatory and legislative mandates enacted at the federal and state level that will have significant 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 by the year 2020. On September 8, 2016, the Governor of California expanded on this bill by approving Senate Bill 32 (SB 32), which requires the state board to ensure that statewide greenhouse gas emissions are reduced to 40% below the 1990 level by 2030.

AB 32 tasked the California Air Resources Board (CARB) to develop regulations for GHG, which became effective January 1, 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 more 19 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC19
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than 25,000 metric tons of carbon dioxide-equivalent greenhouse gases per year. In 2015, the program expanded to cover emissions from transportation fuels, natural gas, propane, and other fossil fuels. Since the enactment of AB 32, the Electric Utility has actively participated with major investor-owned utilities and other publicly-owned utilities (POUs) to affect the 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 associated with generating electricity. CARB will provide a free allocation of GHG allowances to each electric utility to mitigate retail rate impacts. If a utility requires additional allowances, then they must be purchased through the auction or on the secondary market to offset its associated GHG emissions. Each allowance can be used for compliance purposes in the current year or carried over for use for future year compliance. The Electric Utility’s free allocation of GHG allowances is expected 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 the quarterly allowance auctions administered by CARB. Proceeds from the auctions must be used for the intended purposes as specified in AB 32, which include but are not limited to procurement of renewable resources, energy efficiency and conservation programs and measures that provide clear GHG reduction benefits. The Electric Utility is segregating the proceeds from the sales of allowances in the auctions as a restricted asset.

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-term financial commitments (commitments greater than five years in duration) for generating resources with capacity factors greater than 60 percent that exceed a GHG emission factor of 1,100 pounds per megawatt hour (lbs./MWh). SB 1368 essentially prohibits any long-term investments in generating resources based on coal. Thus, SB 1368 initially disproportionally 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 of existing coal resources to serve load.

The City has ownership entitlement rights to 136 MW of the Intermountain Power Plant (IPP). IPP has a GHG emission factor of approximately 2,000 lbs./MWh. Therefore, under SB 1368, the City is precluded from renewing its IPP Power Purchase 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 of California load served by coal resources is small. However, to the extent that significant numbers of coal plants throughout the western United States (U.S.) start to retire in the next 5 to 15 years, it is possible that there can be a tightening of supply throughout the western U.S. electricity market. In turn, this can lead to higher regional costs and potentially reduced system 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 reporting timeline of the energy storage targets referenced in AB 2514. The law directs the governing boards of POUs to consider setting targets for energy storage procurement, but emphasizes that any such targets must be consistent with technological viability and cost effectiveness. The law’s main directives for POUs and their respective deadlines are as follows: (a) to open a proceeding by March 1, 2012 to determine appropriate targets, if any, for the utility to procure viable and 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 2 nd target to be achieved by December 31, 2020. POUs were required to submit compliance reports to the CEC of their first adopted target by January 1, 2017.

Energy storage (ES) has been advocated as an effective means for addressing the growing operational problems of integrating intermittent renewable resources, as well as contributing to other applications on and off the grid. In general, ES is 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 hydro generation, 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 to investigate the various energy storage technologies available and determine if the City should adopt a 2016 energy storage procurement target. The City finished its investigation of energy storage pricing and benefits in September 2014 and adopted a zero-megawatt target based on the conclusion that the viable applications of energy storage technologies and solutions at the time were not cost effective and outweighed the benefits that it might provide to our electrical system. The 20 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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City had to reevaluate its assessment by October 1, 2017 and report to the CEC any modifications to its initial target resulting from this reevaluation.

On March 3, 2015, City Council approved the Ice Bear Pilot program for 5 MW. The program is intended to reduce load during peak hours by shifting load to off-peak hours, improve energy efficiency, and demonstrate the City’s proactive support of the State’s energy storage goals. Additionally, on July 28, 2015, the City Council approved a 20-year power purchase agreement for the City to procure renewable energy from the Antelope DSR Solar Photovoltaic Project that includes 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 efforts in investigating viable energy storage options in the market and conducting energy storage pilot projects within the City to fulfill its first adopted target.

On September 11, 2017 and September 26, 2017, after reevaluating its assessment of the first adopted energy storage procurement target of zero megawatts, the Riverside Board and City Council, respectively, approved and adopted the second 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 makes up 63% of total storage capacity and serves 17 gas fired power generation units. On May 10, 2016, the Governor of California signed SB 380 placing a moratorium on Aliso Canyon’s natural gas storage usage until rigorous tests were performed and completed by the Division of Oil, Gas, and Geothermal Resources (DOGGR) as to which wells could continue to be in operation. This moratorium caused great concern regarding reliability in the upcoming summer and winter months. An action plan was initiated to review the summer and winter assessment. This action plan was conducted as a joint effort between the California Public Utilities Commission (CPUC), CEC, CAISO, and Los Angeles Department of Water and Power (LADWP). Although the area of study does not include nor immediately impact Riverside, it is highly plausible that the Electric Utility could still experience curtailed gas deliveries under certain adverse low-flow gas scenarios.

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 in place to reduce the probability of natural gas curtailments, which would disproportionally impact Riverside due to the requirements to operate internal natural gas generation to maintain system reliability during the summer. Also, gas curtailments during high peak days could lead to severe service curtailments throughout Riverside. Therefore, the Electric Utility immediately increased internal communication across divisions, created internal gas curtailment procedures to address this specific issue, and created revised dispatch procedures when load forecasts exceed 400 MW. These tighter OFO tariff restrictions were scheduled to conclude upon the return of Aliso Canyon to at least 450 million cubic feet per day (MMcfd) of injection capacity and 1,395 MMcfd of withdrawal capacity. Aliso Canyon had not been able to meet its injection 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 our service territory.

On February 9, 2017, pursuant to SB 380, the CPUC opened a three-phase investigation to determine the feasibility of minimizing or eliminating the use of Aliso Canyon. On July 19, 2017, DOGGR issued a press release on their determination, in concurrence with the CPUC, that Aliso Canyon was safe to resume injections up to 28% of the facility’s maximum capacity. On that same day, the CEC issued a different press release with a recommendation urging closure of Aliso Canyon in the long-term. On July 31, 2017, SoCalGas resumed injections. Effective July 23, 2019, the CPUC approved the Aliso Canyon Withdrawal Protocol, a protocol describing the process to follow before making a withdrawal from the natural gas storage facility. The protocol was developed with input from the CEC, the CAISO, and LADWP, and enables SoCalGas to withdraw from the Aliso Canyon natural gas storage facility when specific conditions are met related to Low Operational Flow Order (OFO) calculations, Southern California natural gas inventory levels, and/or emergency conditions.

Senate Bill 380 added Section 715 to the Public Utilities Code (PUC), which requires the CPUC to determine the range of Aliso 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 to 34 billion cubic feet (Bcf) for summer 2018 and going forward, due to continuing pipeline outages on the SoCalGas system. On May 27, 2020, the CPUC granted SoCalGas permission to withdraw natural gas from Aliso Canyon for cleanup purposes, and on February 8, 2021, approved withdrawals for performance flow testing. As of October 7, 2020, the final 21 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC21
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results of the 114 injection well tests are as follows: 66 wells have completed all required 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 CalGEM reduced the Aliso Canyon safe inventory limit from 86Bcf to 68.6Bcf.

On November 4, 2021, the CPUC voted to allow SoCalGas to increase the amount of natural gas inventory at the Aliso Canyon 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 Canyon Natural Gas Storage Facility is needed to maintain the reliability of the natural-gas system and to help stabilize gas and electric rates until other resources are available to serve the Los Angeles Basin. In the same Ruling, the CPUC sought comments on a Staff Proposal presenting a framework to eliminate the need for Aliso Canyon by increasing non-gas-fired electricity generation and storage, building electrification, and energy efficiency. The proposal quantifies the current need for Aliso Canyon and estimates an annual increase of 1,084 MW of non-gas-fired electric generation capacity to reliably serve all energy demand without the use of Aliso Canyon by 2027. Because natural gas and electricity systems and demands are constantly evolving, this proposal suggests a biennial assessment where staff from the CPUC and CEC update 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 exceed targets, staff would recommend whether the maximum storage inventory at Aliso should be reduced. This process would continue 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 low storage inventories. On August 31, 2023, the CPUC approved an increase to the maximum storage level allowed at Aliso Canyon from 41.16Bcf up to the safety limit set by CalGEM of 68.6Bcf. The decision allows more natural gas to be injected and stored at Aliso Canyon to help secure energy reliability and protect against high natural gas and electric prices. The decision 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 was amended to include a biomass procurement mandate for local publicly-owned utilities serving more than 100,000 customers. These utilities would be required to procure their pro-rata share of the statewide obligation of 125 MW based on the ratio of the utility’s peak demand to the total statewide peak demand from existing in-state bioenergy projects for at least 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 the 125 MW statewide mandate. The City determined that their obligated share would be 1.3 MW to meet the mandate. It is expected that the City’s proportion of these facilities will be counted towards the Electric Utility’s Renewable Portfolio Standard (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 be beneficial to procure a contract together for economies of scale. This was accomplished by utilizing SCPPA to issue a Request for Proposal on behalf of all the affected POUs, since four of the seven POUs affected are existing SCPPA members.

In January 2018, the Riverside Board and City Council approved the City’s five-year Power Sales Agreement with SCPPA for 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 ability to prevent and recover from catastrophic wildfires such as via forest management activities, updating requirements for maintenance and operations of utility infrastructure, assessing GHG emissions impact, and protecting ratepayers. The bill also included a clause for certain biomass contracts that were procured or operating in 2018 and set to expire on or before December 31, 2023 to be offered a contract extension. The Electric Utility is required to “seek to amend the contract to include, or seek approval for a new contract that includes, an expiration date 5 years later than the expiration in the contract”. Although there is no enforcement mechanism, the ARP-Loyalton biomass project meets the above criteria and feedstock requirement referenced in SB 901 and SB 859. The Electric Utility had been working with ARP-Loyalton to comply 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, but court proceedings are still ongoing to finalize terms and conditions. 22 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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On February 24, 2020 and March 17, 2020, Riverside's Board and City Council, respectively, adopted a five-year Purchase Agreement 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 of 2015. 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 the transformation of the CAISO into a regional organization. In addition, there is a specific integrated resource planning mandate embedded in the bill that applies to the 16 POUs that have an annual electrical demand exceeding 700 GWh over 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, 2019 and be incorporated into the Electric Utility’s Integrated Resource Plan (IRP). An Updated 2018 Renewable Energy Procurement 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 for updating the plan at least once every 5 years. The IRP must address specific topics such as energy efficiency and demand response resources, transportation electrification, GHG emissions, energy storage resources, enhanced distribution systems and demand-side management, etc. The IRP must be submitted to the CEC for review, of which the CEC will check if the statutory requirements have been met and will adopt guidelines to govern the submission of the IRP information. 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 as part of the IRP process the role of existing renewable generation, grid operational efficiencies, energy storage, energy efficiency, and distributed energy resources in meeting the energy and reliability needs of each utility during the hours of peak demand. On August 1, 2018, the CEC adopted a Second Edition of the POU IRP Submission and Review Guidelines to include the requirements of SB 338. On October 3, 2018, the CEC adopted an amendment to the second edition guidelines 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 the Electric Utility’s 2018 Integrated Resource Plan. The IRP and additional submittal requirements were submitted to the CEC on December 18, 2018. In April 2019, the CEC issued their Staff Paper Review of the Electric Utility’s IRP, as well as the CEC 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.

The CEC continues to host various workshops on different components of the SB 350 requirement and the Electric Utility has been monitoring its outcome.

ASSEMBLY BILL (AB) 1110 AND SENATE BILL (SB) 1158 - LEGISLATION RELATING TO GREENHOUSE

GAS EMISSIONS REPORTING FOR POWER RESOURCE DISCLOSURE
On September 26, 2016, AB 1110 was signed into law requiring GHG emissions intensity data and unbundled renewable energy credits (RECs) to be included as part of the retail suppliers’ power source disclosure (PSD) report and power content label (PCL) to their customers. GHG emissions intensity factors will need to be provided for all retail electricity products. The inclusion of this new information requirement on the PCL will begin in 2021 for calendar year 2020 data. In addition to still being required to post the PCL on the city website, the bill also reinstated the requirement that the PCL disclosures must be mailed to the customers starting in 2017 for calendar year 2016 data unless customers have opted for electronic notifications. In accordance with this requirement, Riverside reinstated the inclusion of printed disclosures of the PCL with its September 2017 bills to the customers.

In 2017, the CEC began hosting workshops on the GHG emissions disclosure requirements and initiated the rulemaking process of updating their PSD regulations. A pre-rulemaking phase also began that included an implementation proposal on AB 1110. The legislation requires the CEC to adopt guidelines by January 1, 2018. In early 2018, the CEC provided an update to their 2017 pre-rulemaking activities and proposed changes to the regulations and reports, but additional workshops were needed. In March 2019, the last pre-rulemaking workshop was held by the CEC, with the intent to begin the formal rulemaking in May, but was delayed until September 2019. On December 11, 2019, the CEC adopted the updated PSD regulations, which changed the timing of the inclusion of the GHG emissions intensity data to be included in the PCL starting in 2021 for calendar year 2020 data. The adoption of the updated PSD regulations and how the additional GHG emissions intensity information would be conveyed to customers in the PSD report and PCL was approved on May 4, 23 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC23
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2020. The most notable changes to the report and label are the addition of the GHG emissions intensity and how certain energy 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 retail supplier to annually report to the CEC information concerning electricity supply used to serve load, including the retail supplier's hourly sources of electricity and the emissions of GHG associated with those sources of electricity. The bill also requires the CEC to share and publish the information annually on its website in an aggregated summary. The CEC is required to adopt rules to implement these reporting requirements on or before July 1, 2024. Currently the CEC is in a pre- rulemaking period but is expected to enter a formal rulemaking period in Fall 2023. Riverside continues to monitor upcoming workshops and draft regulations for any impacts 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 legislative package that will be discussed further below. In addition, AB 398 required the CARB to update their scoping plan no later than January 1, 2018. AB 398 also requires all adopted GHG rules and regulations to be consistent with this plan. On July 27, 2017, the CARB approved the 2016 Cap-and-Trade Amendments, which includes the Electric Utility’s 2021-2030 allowance allocations it will receive each year. The Electric Utility’s allowance allocations should be sufficient to cover all of its 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 the market and then purchase allowances to fulfill its compliance obligations. Since the start of the Cap-and-Trade program in 2012, POUs have been able to directly assign allowances for compliance. However, in 2017, the CARB announced they were reconsidering this provision. In early 2018, after much discussion and collaboration with the CARB in which the POUs demonstrated that they continue to include the price of GHG emissions in the cost of energy, it was agreed that the POUs would not be forced to consign their allocated direct-compliance allowances to auction. Other unknown components of the law include the banking provisions and the specific GHG revenue spending requirement for revenues generated from the sale of excess allowances.

In June 2021, the CARB began focus area discussion workshops as part of the next iteration of the Scoping Plan Update on four areas: 1) electricity sector, 2) transportation sector, 3) equity and environmental justice, and 4) natural and working lands. On June 8, 2021, the CARB hosted a workshop series to commence development of the 2022 Scoping Plan Update to Achieve Carbon Neutrality by 2045. Starting in July 2021 and onward, a series of technical workshops were hosted to cover various topics and sectors within the Scoping Plan. On December 15, 2022, the CARB Board unanimously adopted the 2022 Scoping Plan Update. The Scoping Plan focuses on laying out the path to achieving carbon neutrality and reducing anthropogenic GHG emissions by 85 percent below 1990 levels no later than 2045. The 2022 Scoping Plan includes decarbonization through the electrification of transportation and buildings which will increase the transportation and generation needs of the Electric Utility. The Scoping Plan also states that storage and demand-side management will be 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 is again proposing the requirement for consignment of POU allocations, which would add significant cost uncertainty into energy 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 Reporting Requirement (MRR). The CARB has shown a particular interest in ensuring that allowance value targets low-income and priority communities. It is anticipated that the formal rulemaking will begin in late 2023 or early 2024 with the goal of the new regulations becoming effective January 1, 2025. The Electric Utility will continue to monitor the outcome and impacts of the upcoming regulations on its service territory and ratepayers.

ASSEMBLY 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 extension of the Cap-and-Trade Program in the State. AB 617 addresses the disproportionate impacts of air pollution in areas impacted by a combination of economic, health, and environmental burdens. These burdens include combinations of poverty, high unemployment, health conditions such as asthma and heart disease, air and water pollution, and hazardous wastes. Both the CARB and local air districts are required to take specific actions to reduce air pollution and toxic air contaminants from commercial and industrial sources, including from electricity-generating facilities. The bill required the CARB, by October 1, 2018, to prepare a statewide monitoring plan regarding technologies and reasons for monitoring air quality and, based on that plan, identify the highest priority locations for the deployment of community level air monitoring 24 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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systems. 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 support community participation in the programs. In turn, this effort would require the local air district of the selected community to adopt a community emissions reduction program.

Additionally, AB 617 requires the CARB to develop uniform reporting standards for criteria air pollutants and toxic air contaminants for specific uses, including electricity-generating facilities. Air districts are to adopt an expedited schedule for implementing 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 and SCAQMD have held and continue to hold community meetings to implement the required elements of AB 617. Preliminary discussions and proposals have already been conveyed by community members from the City as well as from the University of California, Riverside proposing areas for community air monitoring and planning. The City and Electric Utility are 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 DISCLOSURE

PROGRAM
On October 8, 2015, AB 802 was signed into law creating a new statewide building energy use benchmarking and public disclosure program for the State of California. The bill requires California utilities to maintain records of energy usage data for all buildings (i.e., commercial and multifamily buildings over 50,000 square feet gross floor area) for at least the most recent 12 months. Beginning January 1, 2017, utilities are required to deliver or provide aggregated energy usage data for a covered building, as defined, to the owner, owner’s agent or operator upon written request. The Electric Utility provides consumption data for buildings meeting the legislative requirement upon owners’ written request. The CEC adopted regulations on October 11, 2017 and approved the regulation action to be effective on March 1, 2018. Building owners are required to report this information annually beginning on June 1, 2018.

SENATE 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 further increases the RPS goals of SBX1-2 and SB 350, while maintaining the 33% RPS target by December 31, 2020, but modifying the future RPS percentages to be 44% by December 31, 2024, 52% by December 31, 2027, and 60% by December 31, 2030. The current end goal of SB 100 is to have 100% of the state's retail electricity supply generated from a 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 will require POUs to procure not less than 60% of retail sales from renewable resources. In September 2019, the CEC began conducting pre-rulemaking workshops to discuss potential amendments to the RPS Enforcement Procedures for POUs that would incorporate the SB 100 mandates. In addition, POUs will need to include the increased requirements in their future IRP. On December 1, 2020, the CEC released the 3 rd 15-day language for the RPS Enforcement Procedures for POUs and adopted it at the December 22, 2020 CEC Business Meeting. It was approved by the Office of Administrative Law (OAL) and made effective July 12, 2021. The updated procedures clarify the interim targets for each year and that compliance periods beginning on and after January 1, 2031, shall be three years in length starting on January 1 and ending on December 31. For each compliance period beginning on or after January 1, 2031, a POU shall demonstrate it has procured electricity products within the compliance period sufficient to meet or exceed an average of 60 percent of the POU'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 and CPUC. The joint agency report is intended to inform policy and planning, which is required to be presented to the legislature every four years starting on January 1, 2021. The final report was published by the CEC and joint agencies on March 15, 2021. On August 22, 2023, the CEC, the CARB, and CPUC held a joint workshop to discuss findings and recommendations from the 2021 SB 100 Joint Agency Report and the plan to address these findings and recommendations as the 2025 SB 100 Joint Agency Report is being developed. Riverside will continue to monitor the outcome and impacts of any upcoming workshops and regulations in meeting the new requirements. 25 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC25
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SENATE BILL (SB) 1028, SB 901 AND ASSEMBLY BILL (AB) 1054 – LEGISLATION RELATING TO

WILDFIRES
On September 24, 2016, Governor Brown signed into law SB 1028, which requires each POU, IOU and electric cooperative to construct, maintain, and operate its electrical lines and equipment in a manner that will minimize the risk of catastrophic 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 by the Governor on September 21, 2018, is meant to address the Governor’s and legislative leaders’ desire to address response, mitigation, and prevention of wildfires. SB 901 requires the Electric Utility to prepare before January 1, 2020 and annually thereafter, a wildfire mitigation plan (WMP) that includes specified information and elements. The Electric Utility must present its WMP in an appropriately noticed public meeting and accept comments on the plan from the public, other local 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 review and assess the comprehensiveness of its plan. The report of the independent evaluator must be made available on the Electric 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 Safety Advisory Board (WSAB), adds an additional process requirement for review of wildfire mitigation plans, and establishes a wildfire fund. In addition to the Electric Utility presenting its WMP to its local governing board by January 1, 2020, the Electric 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.

On December 9, 2020, the WSAB completed their review of all publicly-owned utilities' initial WMPs and issued an advisory opinion applicable to all POUs. It identified several themes that all POUs were requested to address and were not required to incorporate the recommendations as part of the next annual WMP update. Instead, POUs were asked to respond to a matrix of questions to be submitted at the same time as the next update of the WMP. The matrix is not required 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 that the 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 respond to the WSAB's advisory opinion that had not been incorporated into the WMP. Instead of bringing it before the City Council for approval as is, staff opted to remove the item from consideration in order to provide an updated 2021 Riverside Public Utilities WMP to the Riverside Board for approval again. The update to the 2021 Riverside Public Utilities WMP was approved 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 rural electric cooperatives. The advisory opinion included general guidance that applied to all POUs, specific guidance for each POU, and a template with instructions for preparing 2023 plans. All guidance was incorporated into Riverside’s 2023 WMP. The 2023 WMP included the steps, programs, policies, and procedures implemented by the Electric Utility to reduce wildfire risks and minimize impacts to customers. As required by PUC Section 8387, a qualified independent evaluator was contracted to review and assess the 2023 WMP for comprehensiveness. The independent evaluator provided feedback on the plan, which the Electric Utility incorporated by including additional details to further clarify the Electric Utility’s wildfire mitigation measures. Afterwards, the independent evaluator concluded that the Electric Utility’s 2023 WMP was sufficient in meeting the requirements for comprehensiveness. On June 26, 2023 and July 18, 2023, the 2023 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.

For the wildfire fund, only voluntarily participating IOUs are eligible for claims arising from a covered wildfire. The POUs are not required nor able to join due to concerns and issues over complications of funding as a public entity. The bills do not address existing legal doctrine relating to utilities’ liability for wildfires. However, any future legislation that addresses California’s inverse condemnation and strict liability issues for utilities in the context of wildfires could be significant for the Electric Utility. Riverside is regularly engaged with the current WSAB meetings and updates, continues to partner with the Riverside Fire Department and diligently monitor the outcome and impacts of any upcoming legislation and regulations on its service territory and ratepayers.
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ASSEMBLY BILL (AB) 205 – ON-CALL RESOURCES AND ENERGY STORAGE On June 30, 2022, AB 205 was signed into law to address several energy topics but more specifically, on-call emergency supply and load reduction for the state’s electrical grid during extreme events to reduce the risk of blackouts. AB 205 requires the CEC to implement and administer the Distributed Electricity Backup Assets (DEBA) Program to incentivize the construction of cleaner and more efficient distributed energy assets and the Demand Side Grid Support (DSGS) Program to 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. In 2023, the Electric Utility will be participating in the DSGS program utilizing the CEC’s contracted administrator who will manage the direct participation of the Electric Utility’s customers in the DSGS program. Through the program, participating customers receive a financial incentive for on-call load reduction during extreme events and the Electric Utility receives reimbursement for administrative costs to facilitate customer participation. The funding for the DSGS program was authorized by AB 205 and further expanded by AB 102 (signed on July 10, 2023) which stated the funding would be available for five years until June 30, 2027.

On January 27, 2023 the CEC held a workshop to discuss the DSGS program and the DEBA program. Information from this meeting was used to inform the development of the DEBA program. Proposed guidelines were released on August 11, 2023 and the CEC hosted a public workshop to solicit stakeholder feedback on the proposed guidelines on August 15, 2023. The proposed guidelines set aside 25% of program funding for projects in POU territories which would be awarded through grant funding opportunity solicitations. Payment is currently set to be disbursed beginning at the start of commercial operation and then spread over five years. Additional clarification is needed regarding whether project infrastructure costs associated with the project would be eligible for funding and if projects would be authorized to serve as a resource adequacy resource. This program could 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 impacts on its service territory and ratepayers.

ASSEMBLY BILL (AB) 209 – ENERGY AND CLIMATE CHANGE
On September 6, 2023, AB 209 was signed into law authorizing several energy programs to address climate change. One program is the Equitable Building Decarbonization Program. The program provides funding for a Statewide Direct Install Program, Tribal Direct Install Program, a Statewide Incentive Program, and provides support for existing programs. This program must serve under-resourced communities and can fund eligible measures such as heating and cooling, building envelope retrofits, water heating, cooking, and more. Draft guidelines were released on May 4, 2023 and final guidelines are anticipated to be adopted in Fall 2023 with the program expected to rollout to initial communities in 2024-2025.

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 provides incentives to support existing, new, and emerging distributed energy resources installed on the customer’s side of the utility meter. Qualifying technologies include wind turbines, fuel cells, advanced energy storage systems and more. On July 10, 2023, the Governor approved Senate Bill (SB) 123, clarifying that SGIP incentives are eligible for low-income residential customers who install behind-the-meter energy storage or photovoltaic systems. It also clarified that these incentives are available to POU customers.

Another program under AB 209 that the CEC must establish and administer is the Hydrogen Program to provide financial incentives 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 Hydrogen Program and the proposed program scope, funding areas, and project requirements. On May 19, 2023 the CEC released a draft solicitation concept for large-scale centralized production to solicit public feedback. On May 23, 2023 the CEC released the “Cost Share for Federal Clean Energy Funding Opportunities” competitive solicitation.

The Electric Utility will continue to monitor the development of these programs to determine opportunities and impacts on its service territory and ratepayers.

FIVE-YEAR ELECTRIC RATE PLAN
On May 22, 2018, the City Council approved a five-year Electric Rate Plan; the final annual rate increase of 3.0% was effective January 1, 2023 and was in effect through June 30, 2023. 27 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC27
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On September 19, 2023, the City Council approved a new five-year Electric Rate Plan, which includes system average annual rate increases. The first rate increase is effective January 1, 2024 with the following four years effective on January 1 of each year. The approved five-year Electric Rate Plan includes annual reviews of the adopted rates by City Council.

The system average rate increases effective January 1, 2024 through 2026 are 7.0%, followed by system average rate increases of 2.0% in years four and five. The Electric Rate Plan was designed to provide financial stability and correct the 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 for sustainability began in 2001 when the City began using light-emitting diodes in all City traffic signals to reduce electricity usage. 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 Action Plans, the most recent in 2012. Most recently, the City adopted the Envision Riverside 2025 Strategic Plan in October 2020. This plan incorporates sustainability throughout as a cross cutting value and environmental stewardship as 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 the Riverside Restorative Growthprint (2016).

The City hosts community-wide Green Riverside Leadership Summits. Since 2012, summits have been held every 2 to 3 years. Events in 2012 and 2019 were in partnership with the University of California Riverside. Events in 2014 and 2016 were 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 California Department of Conservation named Riverside its first "Emerald City" in recognition for its sustainable green initiatives and commitment to help the state achieve multiple state environmental priorities. The City was honored in 2016 with the Green Community 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 ongoing community-wide sustainability projects and programs that create environmental awareness and action throughout the community, including business, government and private citizens. The Green California Leadership Summit again recognized the City in 2018 with its Leadership Award for the City Green Fleet Program. Additionally, in 2022, Riverside was 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 information and tips on energy efficiency and water conservation best practices. There were electric vehicle demonstrations and experts on hand to advise on how to incorporate native plants in local landscapes. Earth Day 2023 was marked by another community celebration day, hosted in collaboration with the City’s Insect Fair. This year, the RPU team was able to expand on the previous messaging and outreach at this bigger event. RPU hosted several booths and the Wyland interactive truck, which provided a hands-on experience for attendees to learn in detail about water conservation and energy efficiency, and the changes they could make towards achieving these goals.

The Electric Utility supports the local economy by offering some of the lowest commercial electric rates in Southern California combined with attractive economic development electric discount rates to qualified new and expanded load customers. These rate programs have helped create and retain over 3,600 jobs in the City since 2010. In late 2021, the Utility relaunched the commercial energy audit program, which provides Key Account customers with a comprehensive energy efficiency plan, a priority list of recommended energy efficiency measures, an estimated return on investment and applicable utility incentives. To date, several key customers have utilized this program, resulting in approximately 700,000 kWh annual savings this year. More audits are planned over the coming months.

Beyond rate incentives, the Electric Utility also offers local businesses a comprehensive assortment of water and energy efficiency programs to improve building efficiency and reduce customer electric consumption. Fiscal year 2021/22 commercial energy efficiency programs saved a total of 4.2 million kWh. Fiscal year 2022/23 saw increased energy efficiencies being realized, with almost 7.3 million kWh saved via RPU's programs.

All of these efforts support organizations and companies in meeting their sustainability goals. Most recently, the State of California’s Air Resources Board relocated their Southern California headquarters to the City of Riverside. The campus opened 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 the overall sustainability and energy efficiency of a building. This facility, through a combination of on-site solar PV and a 100% 28 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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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 reduced maintenance costs. Additionally, the Utility’s Energy, Water and Custom Energy technology grant programs continue to encourage local higher education institutions and business electric customers to submit proposals for potential grant funding 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 job creation 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 any information provided in this report or requests for additional financial information should be addressed to the Assistant General Manager – Business Systems and Customer Service, Riverside Public Utilities, 3750 University Avenue, 5th floor, Riverside, CA 92501. Additional financial information can also be obtained by visiting www.RiversidePublicUtilities.com. 29 MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC29
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FINANCIAL STATEMENTS

STATEMENTS OF NET POSITION
June 30,
2023
June 30,
2022
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES (in thousands) NON-CURRENT ASSETS:

Capital assets:

Utility plant, net of accumulated depreciation (Note 3) $ 784,916 $ 795,736 Lease and subscription assets, net of amortization (Note 3) 405 491 Total capital assets 785,321 796,227
Restricted assets:

Cash and investments at fiscal agent (Note 2) 58,135 53,785 Total non-current restricted assets 58,135 53,785
Other non-current assets:

Advances to other funds of the City 2,003 2,454
Lease receivable (Note 14) 10,407 7,099
Unamortized purchase power (Note 11) 11,664 12,317
Regulatory assets 1,573 1,665
Net pension asset (Note 6) - 26,219
Total other non-current assets 25,647 49,754
Total non-current assets 869,103 899,766
CURRENT ASSETS:

Unrestricted assets:

Cash and cash equivalents (Note 2) 247,831 274,172
Accounts receivable, less allowance for doubtful accounts 2023 ($3,351); 2022 ($2,996) 37,260 50,093
Accrued interest receivable 1,033 663
Leases receivable (Note 14) 1,359 990
Inventory 1,464 485
Prepaid expenses 6,168 6,127
Unamortized purchase power (Note 11) 666 653
Total unrestricted current assets 295,781 333,183
Restricted assets:

Cash and cash equivalents (Note 2) 44,794 38,526
Public Benefit Programs - cash and cash equivalents (Note 2) 29,152 25,032 Public Benefit Programs receivable 1,070 1,485
Total restricted current assets 75,016 65,043
Total current assets: 370,797 398,226
Total assets 1,239,900 1,297,992
DEFERRED OUTFLOWS OF RESOURCES:

Deferred outflows related to pension (Note 6) 34,931 9,168 Deferred outflows related to other postemployment benefits (Note 7) 1,592 1,805 Changes in derivative values 1,571 5,924
Loss on refunding 7,530 8,046
Total deferred outflows of resources 45,624 24,943
Total assets and deferred outflows of resources $ 1,285,524 $ 1,322,935 See accompanying notes to financial statements
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FINANCIAL STATEMENTS

STATEMENTS OF NET POSITION
June 30,
2023
June 30,
2022
NET POSITION, LIABILITIES AND DEFERRED INFLOWS OF RESOURCES (in thousands) NET POSITION:

Net investment in capital assets $ 254,990 $ 246,698
Restricted for:

Regulatory requirements(Note 8) 25,502 19,598
Debt service (Note 8) 19,332 18,967
Public Benefit Programs 29,329 25,857
Unrestricted 174,199 194,443
Total net position 503,352 505,563
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (Note 4) 590,602 615,834 OTHER NON-CURRENT LIABILITIES:

Compensated absences (Note 5) 1,889 2,426
Net pension liability (Note 6) 38,748 -
Nuclear decommissioning liability (Note 10) 38,646 44,497 Other postemployment benefits liability (Note 7) 9,420 10,066 Derivative instruments (Note 4) 4,097 8,905
Regulatory liability 4,675 4,220
Lease liability (Note 14) 225 363
SBITA liability (Note 14) 7 -
Total other non-current liabilities 97,707 70,477
CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS:

Accrued interest 5,083 5,465
Public Benefit Programs payable 866 624
Nuclear decommissioning liability (Note 10) 10,227 8,813 Current portion of long-term obligations (Note 4) 22,633 20,992 Total current liabilities payable from restricted assets 38,809 35,894 CURRENT LIABILITIES:

Accounts payable and other accruals 19,584 22,722
Compensated absences (Note 5) 5,589 4,774
Customer deposits 11,734 11,888
Unearned revenue 314 1,412
Other postemployment benefits liability (Note 7) 417 394 Current portion of long-term obligations (Note 4) - 364 Lease liability (Note 14) 137 134
SBITA liability (Note 14) 42 -
Total current liabilities 37,817 41,688
Total liabilities 764,935 763,893
DEFERRED INFLOWS OF RESOURCES:

Deferred inflows related to pension (Note 6) 3,577 44,089 Deferred inflows related to other postemployment benefits (Note 7) 2,266 1,426 Lease related items (Note 14) 11,394 7,964
Total deferred inflows of resources 17,237 53,479
Total net position, liabilities and deferred inflows of resources $ 1,285,524 $ 1,322,935 See accompanying notes to financial statements
31 FINANCIAL STATEMENTS: ELECTRIC31
ELECTRIC UTILITY:

FINANCIAL STATEMENTS

STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION For the Fiscal Years
Ended June 30,
2023 2022
(in thousands)
OPERATING REVENUES:

Residential sales $ 140,538 $ 134,403
Commercial sales 77,191 75,899
Industrial sales 124,600 122,684
Other sales 5,162 4,891
Wholesale sales 2,043 89
Transmission revenue 35,233 32,245
Other operating revenue 24,403 18,758
Public Benefit Programs 10,222 8,978
Total operating revenues before uncollectibles 419,392 397,947 Estimated uncollectibles, net of bad debt recovery (475) 681 Total operating revenues, net of uncollectibles 418,917 398,628 OPERATING EXPENSES:

Production and purchased power 195,914 176,595
Transmission 68,052 65,996
Distribution 68,057 39,738
Public Benefit Programs 6,751 5,467
Depreciation 38,189 36,718
Amortization 214 134
Total operating expenses 377,177 324,648
Operating income 41,740 73,980
NON-OPERATING REVENUES (EXPENSES):

Investment (loss) income 5,952 (10,330)
Interest expense and fiscal charges (23,775) (25,037)
Gain on sale of assets 957 505
Other 5,387 6,589
Total non-operating revenues (expenses) (11,479) (28,273) Income before capital contributions and operating transfers out 30,261 45,707 Capital contributions 9,854 7,667
Transfers out - contributions to the City's general fund (42,326) (39,436) Total capital contributions and transfers out (32,472) (31,769) EXTRAORDINARY ITEM (Note 13):

San Onofre Nuclear Generating Station additional requirement for plant closure - (5,748) Change in net position (2,211) 8,190
NET POSITION, BEGINNING OF YEAR 505,563 497,373
NET POSITION, END OF YEAR $ 503,352 $ 505,563
See accompanying notes to financial statements
32 FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

FINANCIAL STATEMENTS

STATEMENTS OF CASH FLOWS
For the Fiscal Years
Ended June 30,
2023 2022
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:

Cash received from customers and users $ 430,913 $ 394,707 Cash paid to suppliers for goods and services (290,354) (252,247) Cash paid to employees for services (56,730) (47,823)
Net cash provided/(used) by operating activities 83,829 94,637 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:

Cash transfers out (42,326) (39,436)
Payment receipt from advances to other funds 451 471
Debt service payment on pension obligation bonds (4,232) (3,310) Other non-operating receipts 5,140 6,463
Net cash provided/(used) by non-capital financing activities (40,967) (35,812) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:

Acquisition and construction of capital assets (27,183) (32,361) Principal paid on capital debt (17,124) (16,581)
Interest paid on capital debt (26,149) (25,645)
Contributions 4,951 5,445
Proceeds from sales of capital assets 5,673 535
Lease and subscription payments (215) (126)
Net cash provided/(used) by capital and related financing activities (60,047) (68,733) CASH FLOWS FROM INVESTING ACTIVITIES:

Income (loss) from investments 5,582 (10,407)
Proceeds from/(purchase of) investment securities (4,350) 6,164 Net cash provided/(used) by investing activities 1,232 (4,243) Net increase/(decrease) in cash and cash equivalents (15,953) (14,151) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $63,558 and $64,587 at June 30, 2022 and June 30, 2021, respectively, reported in restricted accounts) 337,730 351,881
CASH AND CASH EQUIVALENTS, END OF YEAR (including $73,946 and $63,558 at June 30, 2023 and June 30, 2022, respectively, reported in restricted accounts) $ 321,777 $ 337,730 See accompanying notes to financial statements
33 FINANCIAL STATEMENTS: ELECTRIC33
ELECTRIC UTILITY:

FINANCIAL STATEMENTS

STATEMENT OF CASH FLOWS
For the Fiscal Years
Ended June 30,
2023 2022
(in thousands)

RECONCILIATION OF OPERATING INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES:

Operating income (loss) 41,740 73,980
Adjustments to reconcile operating income/(loss) to net cash provided/(used) by operating activities:

Depreciation 38,189 36,718
Amortization 214 134
(Increase) decrease in utility billed receivable 9,137 (3,908) (Increase) decrease in utility unbilled receivable 2,985 (931) (Increase) decrease in accounts receivable 732 (1,487)
(Increase) decrease in prepaid items 679 1,482
(Increase) decrease in deposits (79) -
(Increase) decrease in inventory (979) 485
(Increase) decrease in intergovernmental receivable (20) 18 Increase (decrease) in accounts payable (3,494) 4,044
Increase (decrease) in accrued payroll 192 407
Increase (decrease) in retainage payable 164 134
Increase (decrease) in decommissioning liability (4,438) (3,334) Increase (decrease) in Public Benefit Programs payable 242 385 Increase (decrease) in deposits payable (154) 1,325
Increase (decrease) in unearned revenue (1,097) 1,345
Increase (decrease) in compensated absences 278 18
Increase (decrease) in net pension liability (1,308) (16,425) Increase (decrease) in OPEB liability 431 530
Increase (decrease) in Public Benefit Program receivable 415 (283) Total adjustments 42,089 20,657
Net cash provided/(used) by operating activities $ 83,829 $ 94,637 SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:

Capital contributions - capital assets $ 4,903 $ 2,222
Increase (decrease) in fair value of investments (529) (2,656) See accompanying notes to financial statements
34 FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Electric Utility exists under, and by virtue of, the City of Riverside (the City) Charter enacted in 1883. The Electric Utility is responsible for the generation, transmission, and distribution of electric power for sale in the City. The accompanying 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 operations of the City in conformity with generally accepted accounting principles. However, certain disclosures are for the City as a whole, since such information is generally not available for the Electric Utility on a separate fund basis. All amounts, unless otherwise indicated, are expressed in thousands of dollars.

BASIS OF ACCOUNTING
The Electric Utility uses the accrual basis of accounting as required for enterprise funds with accounting principles generally accepted in the United States of America as applicable to governments. The accounting records of the Electric Utility are also substantially in conformity with the Uniform System of Accounts prescribed by the Federal Energy Regulatory 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 and expenses generally result from providing services and producing and delivering goods in connection with an enterprise fund’s principal ongoing operations. The principal operating revenues of the Electric Utility are charges to customers for electric 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 are reported as non-operating revenues and expenses.

IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENTS
In November 2016, the GASB issued Statement No. 83, Certain Asset Retirement Obligations (GASB 83). This Statement addresses accounting and financial reporting for certain asset retirement obligations (AROs). An ARO is a legally enforceable 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 liability recognition when it is incurred and reasonably estimable, and (3) requires ARO measurement to be based on the best estimate of the current value of outlays expected to be incurred. If an ARO has been incurred but is not yet recognized because it is not reasonably estimable, the government is required to disclose that fact and the reasons therefor. This Statement will enhance comparability of financial statements among governments by establishing uniform criteria for governments 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 Riverside purchased the Clearwater Power Plant (the “Plant”) from the City of Corona to own, operate, and pay all costs related to the Plant and the assets, as set forth in the agreement. On August 26, 2010, Temporary Right of Entry Agreement was made and entered into between the City of Riverside (“Riverside”) and the City of Corona (“Corona”) in which Corona leased the Corona Clearwater Cogeneration Facility (the “Property”) to Riverside for its operation and maintenance of the Property. Riverside is responsible for plant decommissioning and site restoration related to the Plant. The ARO evaluation study to measure the obligation was completed in fiscal year 2019/20. However, since Riverside does not have the final lease agreement with Army Corps to determine the life of the plant, a liability and deferred outflow will not be recorded in fiscal year 2022/23.

The following new Governmental Accounting Standards Board (GASB) pronouncements were effective and have been implemented for fiscal year 2022-2023 audit:

GASB Statement No. 91, Conduit Debt Obligations - This Statement clarifies the existing definition of a conduit debt obligation; establishes that a conduit debt obligation is not a liability of the issuer; establishes standards for accounting and financial reporting of additional commitments and voluntary commitments extended by issuers and arrangements associated with conduit debt obligations; and improves required note disclosures.

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENTS (CONTINUED) which (1) the operator collects and is compensated by fees from third parties; (2) the transferor determines or has the ability to modify or approve which services the operator is required to provide, to whom the operator is required to provide the services, and the prices or rates that can be charged for the services; and (3) the transferor is entitled to significant residual interest in the service utility of the underlying PPP asset at the end of the arrangement. This Statement also provides guidance for accounting and financial reporting for availability payment arrangements (APAs). An APA is an arrangement in which a government compensates an operator for services that may include designing, constructing, financing, maintaining, or operating an underlying nonfinancial asset for a period of time in an exchange or exchange-like transaction.

GASB Statement No. 96, Subscription-Based Information Technology Arrangements (SBITA) – This Statement defines Subscription-Based Information Technology Arrangements (SBITA) as a contract that conveys control of the right to use another party’s (a SBITA vendor’s) information technology (IT) software, alone or in combination with tangible capital assets (the underlying IT assets), as specified in the contract for a period of time in an exchange or exchange-like transaction. This Statement establishes that a SBITA results in a subscription asset—an intangible asset—and a corresponding subscription liability; (3) provides the capitalization criteria for outlays other than subscription payments, including implementation costs of a SBITA; and (4) requires note disclosures regarding a SBITA. The standards for SBITAs are based on the standards established in Statement No. 87, Leases, as amended.

USE OF ESTIMATES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during a reporting period. Accordingly, actual results could differ from those estimates.

REVENUE RECOGNITION
The Electric Utility customers are billed monthly. Unbilled electric service charges, including Public Benefit Programs, are recorded at year-end and are included in accounts receivable. Unbilled accounts receivable totaled $14,004 at June 30, 2023, and $17,075 at June 30, 2022.

An allowance for doubtful accounts is maintained for the Electric Utility and miscellaneous accounts receivable. The balance in this account is adjusted at fiscal year-end to approximate the amount anticipated to be uncollectible.

ELECTRIC UTILITY PLANT AND DEPRECIATION
The Electric Utility defines capital assets as assets with an initial, individual cost of more than five thousand dollars and an estimated useful life in excess of one year. Electric Utility plant assets are valued at historical cost or estimated historical cost, 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 minor replacements is included in maintenance expense. Intangible assets that cost more than one hundred thousand dollars with 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 estimated useful lives are as follows:

Production plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................10-40 years Transmission and distribution plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................20-50 years General plant and equipment................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-50 years Intangibles................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-10 years 36 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

RESTRICTED ASSETS
Proceeds of revenue bonds yet to be used for capital projects, as well as certain resources set aside for debt service, are classified 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 are also classified as restricted assets because their use is legally restricted to a specific purpose. Generally, the Electric Utility will first apply restricted resources when expenses are incurred for which both restricted and unrestricted resources are available.

In January 1998, the Electric Utility began collecting a surcharge for Public Benefit Programs on customer utility bills. This surcharge is mandated by state legislation included in Assembly Bill 1890 and is restricted to various socially beneficial programs and services. The programs and services include cost effective demand-side management services to promote energy efficiency and conservation and related education and information; ongoing support and new investments in renewable resource technologies; energy research and development; and programs and services for low-income electric customers. The activity associated with the surcharge for Public Benefit Programs is reflected in the accompanying financial statements on the Statements of Net Position, Statements of Revenues, Expenses and Changes in Net Position, and Statements of Cash Flows.

CASH AND CASH EQUIVALENTS
For the Statements of Cash Flows, cash and cash equivalents include all unrestricted and restricted highly liquid investments with original purchase maturities of three months or less, and all bond construction proceeds available for capital projects held at fiscal agent. Pooled cash and investments in the City’s Treasury represent monies in a cash management pool. Such accounts are similar in nature to demand deposits, and are classified as cash equivalents for the purpose of presentation in the Statements of Cash Flows.

CASH AND INVESTMENTS
The Electric Utility’s cash and investments, except for funds required to be held by outside fiscal agents under the provisions of bond indentures, which are administered by outside agencies, are invested in the cash and investment pool of the City.

The Electric Utility values its cash and investments in accordance with provisions of GASB Statement No. 72, Fair Value Measurement and Application, which requires governmental entities to use valuation techniques that are appropriate under the circumstances and for which sufficient data are available to measure fair value. The techniques should be consistent with one or more of the following approaches: the market approach, the cost approach or the income approach. Valuation includes 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 Electric Utility does not value any of its investments using level 3 inputs.

City-wide information concerning cash and investments as of June 30, 2023 , including authorized investments, fair value measurement and application, custodial credit risk, credit and interest rate risk for debt securities and concentration of investments, carrying amount and market value of deposits and investments can be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report.

CASH AND INVESTMENTS AT FISCAL AGENTS
Cash and investments maintained by fiscal agents are considered restricted by the Electric Utility. A portion is pledged as collateral for payment of principal and interest on outstanding bonds and certain funds are set aside to decommission the Electric Utility’s proportionate share of Units 2 and 3 at SONGS. Further details regarding the jointly-owned project SONGS can be found in Note 10.

DESIGNATED CASH RESERVES
The Riverside Public Utilities Cash Reserve Policy establishes several designated cash reserves in the Electric Utility for strategic purposes. Designated reserves are set aside for specific purposes determined by the Board of Public Utilities and City Council. Designated reserves may be held for capital or operating purposes.

Designated cash reserve balances as of June 30, 2023 and 2022 were as follows: Additional Decommissioning Liability Reserve $8,644 and $16,107, Customer Deposits $4,948 and $5,610, Capital Repair and Replacement Reserve $2,287 37 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC37
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

DESIGNATED CASH RESERVES (CONTINUED)
and $2,488, Electric Reliability Reserve $87,127 and $82,261, Mission Square Improvement Reserve $2,113 and $1,533, and Dark Fiber Reserve $4,801 and $4,942. The combined total for these reserves was $109,920 and $112,941 at June 30, 2023 and 2022, respectively, and is included as a component of unrestricted cash and cash equivalents in the accompanying Statements of Net Position.

ADVANCES TO OTHER FUNDS OF THE CITY
Advances to other funds of the City have been recorded as a result of agreements between the Electric Utility and the City.

The balances as of June 30, 2023 and 2022 are $2,003 and $2,454, respectively.

DERIVATIVES
The Electric Utility accounts for derivative instruments using GASB Statement No. 53, Accounting and Financial Reporting for Derivative Instruments (GASB 53). This Statement requires the Electric Utility to report its derivative instruments at fair value. Changes in fair value for effective hedges are to be reported as deferred inflows and outflows of resources on the Statements 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 of Revenues, Expenses and Changes in Net Position.

The Electric Utility has determined that its interest rate swaps associated with variable rate obligations are derivative instruments under GASB 53. See Note 4 Long-Term Obligations for further discussion related to the Electric Utility’s interest rate swaps.

Various transactions permitted in the Electric Utility’s Power Resources Risk Management Policies may be considered derivatives, including energy and/or gas transactions for swaps, options, forward arrangements and congestion revenue rights (CRR). GASB 53 allows an exception for the Statements of Net Position deferral hedges that meet the normal purchases and normal sales exception. The Electric Utility has determined that all of its contracts including CRRs fall under the scope of “normal purchases and normal sales” and are exempt from GASB 53.

BOND PREMIUMS AND GAINS/LOSSES ON REFUNDING
Bond premiums 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 are reported net of the applicable bond premiums. Gains/losses on refunding are reported as deferred inflows or outflows of resources.

CUSTOMER DEPOSITS
The City holds customer deposits as security for the payment of utility bills and design fee deposits for future construction of electrical facilities. The Electric Utility’s portion of these deposits as of June 30, 2023 and 2022 was $11,734 and $11,888, respectively.

COMPENSATED ABSENCES
The accompanying financial statements include accruals for salaries, fringe benefits and compensated absences due to employees at June 30, 2023 and 2022. The Electric Utility treats compensated absences due to employees as an expense and a liability of which a current portion is included in accounts payable and other accruals in the accompanying Statements of Net Position. The amount accrued for compensated absences was $7,478 at June 30, 2023 and $7,200 at June 30, 2022.

Employees receive 10 to 25 vacation days per year based upon length of service. A maximum of two years vacation accrual 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. Upon retirement or death, certain employees or their estates receive a percentage of unused sick leave paid in a lump sum based on longevity.
38 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

INSURANCE PROGRAMS
The Electric Utility participates in a self-insurance program for workers’ compensation and general liability coverage that is administered by the City. The Electric Utility pays an amount to the City based on actuarial estimates of the amounts needed to fund prior and current year claims and incidents that have been incurred but not reported. The City maintains property insurance on most City property holdings, for a shared limit of $1 billion and $210 million to cover power generation facilities.

City-wide information concerning risks, insurance policy limits and deductibles and designation of general fund balance for risk for the year ended June 30, 2023 may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report.

Although the ultimate amount of losses incurred through June 30, 2023 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 the Electric Utility, including the Public Benefit Programs, were $2,058 and $656 for the years ended June 30, 2023 and 2022, respectively. Any losses above the City’s reserves would be covered through increased rates charged to the Electric Utility in future years.

EMPLOYEE RETIREMENT PLAN
The City contributes to the California Public Employees Retirement System (CalPERS), an agent multiple employer 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 and administrative agent for participating public entities within the State of California. Benefit provisions and all other requirements 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 determined on the same basis as they are reported by CalPERS. For this purpose, benefit payments (including refunds of employee contributions) are recognized when due and payable in accordance with the benefit terms. Investments are reported at fair value. Further details of employee retirement plan can be found in Note 6.

OTHER POSTEMPLOYMENT BENEFITS (OPEB)
OPEB refers to the benefits, other than pensions, that the City provides as part of an employee’s retirement benefits. The net OPEB liability is defined as the liability of employers contributing to employees for benefits provided through a defined 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 RESOURCES
When applicable, the Statements of Net Position will report a separate section for deferred outflows of resources. Deferred outflows 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 of changes in derivative values, loss on refunding and deferred outflows related to pension and OPEB, which include pension contributions subsequent to 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 future periods and that, therefore, are not recognized as an inflow of resources (revenue) until that time. Deferred inflows of resources consist of lease related items, deferred inflows related to pension and OPEB, which include changes in assumptions, differences between expected and actual experience, and net differences between projected and actual earnings on pension plan investments.
39 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC39
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

REGULATORY ASSETS
In accordance with regulatory accounting criteria set forth in GASB Codification (GASB Statement No. 62), enterprise funds that are used to account for rate-regulated activities are permitted to defer certain expenses and revenues that would otherwise be recognized when incurred, provided that the Electric Utility is recovering or expects to recover or refund such amounts in rates charged to its customers. Accordingly, regulatory assets relating to debt issuance costs have been recognized in the Statements of Net Position.

NET POSITION
The Electric Utility’s net position represents the difference between assets and deferred outflows of resources less liabilities and deferred inflows of resources, which is classified into the following three components:

Net investment in capital assets – this component consists of capital assets (net of accumulated depreciation) reduced by the outstanding balances of any bonds or other borrowings that are attributable to the acquisition, construction, or improvement of those assets, excluding unspent bond proceeds.

Restricted – 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 or through enabling legislation.

Unrestricted – this component consists of net position that does not meet the definition of “restricted” or “net investment in capital assets.”
CONTRIBUTIONS TO THE CITY’S GENERAL FUND
Pursuant to the City of Riverside Charter, the Electric Utility may transfer up to 11.5 percent of its prior year’s gross operating revenues, including adjustments, to the City’s general fund. In fiscal years ended June 30, 2023 and 2022, $42,326 and $39,436, respectively, was transferred, representing 11.5 percent. Additional information can be found in Note 12 of the accompanying financial statements.

LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS Leases are defined by the general government as the right to use an underlying asset. As lessee, the Electric Utility recognizes a lease liability and a lease asset at the beginning of a lease period unless the lease is considered a short-term lease or transfers ownership of the underlying asset. Lease assets are measured based on the net present value of the future lease payments at inception, using the weighted average cost of capital, which approximate the incremental borrowing rate. Re-measurement of a lease liability occurs when there is a change in the lease term and/or other changes that are likely to have a significant impact on the lease liability. The Electric Utility calculates the amortization of the discount on the lease liability and report that amount as outflows of resources. Payments are allocated first to accrued interest liability and then to the lease liability. Variable lease payments based on the usage of the underlying assets are not included in the lease liability calculations but are recognized as outflows of resources in the period in which the obligation was incurred. As lessor, the Electric Utility recognizes a lease receivable. The lease receivable is measured using the net present value of future lease payments to be received for the lease term and deferred inflow of receivables at the beginning of the lease term. Periodic amortization of the discount on the receivable are reported as interest revenue for that period. Deferred inflows of resources are recognized as inflows on a straight-line basis over the term of the lease. This recognition 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 contract price, lease term, and adding or removing an underlying asset to the lease agreements. In the case of a partial or full lease termination, the carrying value of the lease receivable and the related deferred inflow of resources will be reduced and will include a gain or loss for the difference. For lease contracts that are short-term, the Electric Utility recognizes short-term lease payments as inflows of resources (revenues) based on the payment provisions of the lease contract. Liabilities are only recognized if payments are received in advance, and receivables are only recognized if payments are received subsequent to the reporting period. Additional disclosures regarding regulated leases are in Note 14. 40 NOTES 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)
Subscription-Based Information Technology Arrangements (SBITAs) are contracts that convey control of the right to use another party’s IT software, alone or in combination with tangible capital assets, as specified in the contract for a period of time in an exchange or exchange-like transaction. To determine whether a contract conveys control of the right to use the underlying IT assets, the City assesses both the right to obtain the present service capacity from use of the underlying IT assets 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 the period during which the City has a noncancellable right to use the underlying IT assets, plus the periods covered by the City’s option to extend the SBITA if it is reasonably certain, based on all relevant factors, that the government will exercise that option. Periods for which both the government and the SBITA vendor have an option to terminate the SBITA without permission from the other party (or if both parties have to agree to extend) are cancellable periods and are excluded from the subscription term. Additional disclosures regarding SBITAs are in Note 14.

BUDGET AND BUDGETARY ACCOUNTING
The Electric Utility presents, and the City Council adopts, a biennial budget. The proposed budget includes estimated expenses and forecasted revenues. The City Council generally adopts the Electric Utility’s budget in June biennially via resolution. Per City Council direction, the Electric Utility transitioned from an incremental budget methodology to a priority- based budgeting methodology in fiscal year 2022-2023.

RECLASSIFICATIONS
Certain reclassifications have been made to prior year’s financial statements to conform with the current year’s presentation. Such reclassifications have no effect on the net position or the changes in net position. 41 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC41
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

2. CASH AND INVESTMENTS
Cash and investments at June 30, 2023 and 2022, consist of the following (in thousands):

June 30, 2023 June 30, 2022
Fair Value
Equity interest in City Treasurer's investment pool $ 321,777 $ 337,730 Cash and investments at fiscal agent 58,135 53,785
Total cash and investments $ 379,912 $ 391,515
The amounts above are reflected in the accompanying financial statements as:

June 30, 2023 June 30, 2022
Unrestricted cash and cash equivalents $ 247,831 $ 274,172 Restricted cash and cash equivalents 73,946 63,558
Restricted cash and investments at fiscal agent 58,135 53,785 Total cash and investments $ 379,912 $ 391,515
The investment types in the tables below related to the Electric Utility’s investments in the City Treasurer’s investment pool represent the Electric Utility’s prorated share of the investment types in the investment pool and do not represent ownership interests in the individual investments.
42 NOTES 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 generally accepted accounting principles. The Electric Utility has the following recurring fair value measurements as of June 30, 2023 and 2022:

Investment Type
June 30, 2023
Fair Value
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Investments
not Subject to
Fair Value
Hierarchy
Held by fiscal agent
Money market funds $ 1,263 $ - $ - $ - $ 1,263
Asset-backed securities 3,853 - 3,853 - -
Investment contracts 10,761 - - - 10,761
US Treasury notes/bonds 24,065 - 24,065 - -
Federal agency obligations 3,407 - 3,407 - -
Corp medium term notes 11,264 - 11,264 - -
Supranational securities 3,522 - 3,522 - -
City Treasurer's investment pool1
Money market funds 5,825 - - - 5,825
Joint powers authority pools 62,073 - - - 62,073
Mortgage pass-through securities 10,596 - 10,596 - -
Asset-backed securities 26,896 - 26,896 - -
US Treasury obligations 93,152 - 93,152 - -
Federal agency obligations 44,548 - 44,548 - -
Medium-term corporate notes 67,044 - 67,044 - -
Supranational securities 11,643 - 11,643 - -
Total $ 379,912 $ - $ 299,990 $ - $ 79,922
Investment Type
June 30, 2022
Fair Value
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Investments
not Subject to
Fair Value
Hierarchy
Held by fiscal agent
Money market funds $ 3,728 $ - $ - $ - $ 3,728
Asset-backed securities 3,503 - 3,503 - -
Investment contracts 10,761 - - - 10,761
US Treasury notes/bonds 18,274 - 18,274 - -
Federal agency obligations 3,208 - 3,208 - -
Corp medium term notes 10,745 - 10,745 - -
Supranational securities 3,566 - 3,566 - -
City Treasurer's investment pool1
Money market funds 9,369 - - - 9,369
Joint powers authority pools 52,571 - - - 52,571
Local agency investment fund 39,946 - - - 39,946
Mortgage pass-through securities 13,210 - 13,210 - -
Asset backed securities 26,715 - 26,715 - -
US Treasury obligations 76,259 - 76,259 - -
Federal agency obligations 45,087 - 45,087 - -
Medium-term corporate notes 59,240 - 59,240 - -
Supranational securities 13,748 - 13,748 - -
Neg certificate of deposit 1,585 - 1,585 - -
Total $ 391,515 $ - $ 275,140 $ - $ 116,375
1Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report. 43 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC43
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

2. CASH AND INVESTMENTS (CONTINUED)
Cash and investments distribution by maturities as of June 30, 2023 and 2022 are as follows:

Remaining Maturity (in Months)
Investment Type
June 30, 2023
Fair Value
12 Months
or Less
13 to 36
Months
37 to 60
Months
More than
60 Months
Held by fiscal agent
Money market funds $ 1,263 $ 1,263 $ - $ - $ -
Asset-backed securities 3,853 - 2,065 1,788 -
Investment contracts 10,761 - - - 10,761
US Treasury notes/bonds 24,065 5,356 12,068 6,641 -
Federal agency obligations 3,407 - 3,407 - -
Corp medium term notes 11,264 1,311 8,899 1,054 -
Supranational securities 3,522 - 3,522 - -
City Treasurer's investment pool1
Money market funds 5,825 5,825 - - -
Joint powers authority pools 62,073 62,073 - - -
Mortgage pass-through securities 10,596 1,668 3,847 5,081 - Asset-backed securities 26,896 298 11,998 14,600 -
US Treasury obligations 93,152 15,330 27,517 50,305 -
Federal agency obligations 44,548 10,572 27,062 6,914 - Medium-term corporate notes 67,044 3,347 36,482 27,215 - Supranational securities 11,643 - 11,643 - -
Total $ 379,912 $ 107,043 $ 148,510 $ 113,598 $ 10,761
Remaining Maturity (in Months)
Investment Type
June 30, 2022
Fair Value
12 Months
or Less
13 to 36
Months
37 to 60
Months
More than
60 Months
Held by fiscal agent
Money market funds $ 3,728 $ 3,728 $ - $ - $ -
Asset-backed securities 3,503 - 1,401 2,102 -
Investment contracts 10,761 - - - 10,761
US Treasury notes/bonds 18,274 5,995 4,938 7,341 -
Federal agency obligations 3,208 2,622 586 - -
Corp medium term notes 10,745 - 6,665 4,080 -
Supranational securities 3,566 - 1,687 1,879 -
City Treasurer's investment pool1
Money market funds 9,369 9,369 - - -
Joint powers authority pools 52,571 52,571 - - -
Local agency investment fund 39,946 39,946 - - -
Mortgage pass-through securities 13,210 3,683 7,692 1,835 - Asset backed securities 26,715 - 14,329 12,386 -
US Treasury obligations 76,259 9,172 37,040 30,047 -
Federal agency obligations 45,087 7,029 28,256 9,802 -
Medium-term corporate notes 59,240 2,716 26,624 29,900 - Supranational securities 13,748 - 4,774 8,974 -
Neg certificate of deposit 1,585 1,585 - - -
Total $ 391,515 $ 138,416 $ 133,992 $ 108,346 $ 10,761
1 Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report. 44 NOTES 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, 2023 and 2022 for each investment type:

Ratings as of Year End
Investment Type
June 30, 2023
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds $ 1,263 $ 999 $ - $ - $ 264
Asset-backed securities 3,853 2,815 - - 1,038
Investment contracts 10,761 - - - 10,761
US Treasury notes/bonds 24,065 23,082 - 983 -
Federal agency obligations 3,407 1,376 - - 2,031
Corp medium term notes 11,264 - 2,754 6,612 1,898
Supranational securities 3,522 1,850 - - 1,672
City Treasurer's investment pool1
Money market funds 5,825 5,825 - - -
Joint powers authority pools 62,073 - - - 62,073
Mortgage pass-through securities 10,596 10,596 - - -
Asset-backed securities 26,896 20,340 - - 6,556
US Treasury obligations 93,152 93,152 - - -
Federal agency obligations 44,548 37,720 - - 6,828
Medium-term corporate notes 67,044 2,120 23,200 32,733 8,991 Supranational securities 11,643 5,995 - - 5,648
Total $ 379,912 $ 205,870 $ 25,954 $ 40,328 $ 107,760
Ratings as of Year End
Investment Type
June 30, 2022
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds $ 3,728 $ 2,787 $ - $ - $ 941
Asset-backed securities 3,503 2,869 - - 634
Investment contracts 10,761 - - - 10,761
US Treasury notes/bonds 18,274 18,274 - - -
Federal agency obligations 3,208 3,208 - - -
Corp medium term notes 10,745 - 2,753 6,657 1,335
Supranational securities 3,566 1,879 - - 1,687
City Treasurer's investment pool1
Money market funds 9,369 7,305 - - 2,064
Joint powers authority pools 52,571 - - - 52,571
Local agency investment fund 39,946 - - - 39,946
Morgage pass-through securities 13,210 13,210 - - -
Asset backed securities 26,715 21,272 - - 5,443
US Treasury obligations 76,259 76,259 - - -
Federal agency obligations 45,087 45,087 - - -
Medium-term corporate notes 59,240 - 21,023 32,327 5,890 Supranational securities 13,748 7,106 - - 6,642
Neg certificate of deposit 1,585 - - 1,585 -
Total $ 391,515 $ 199,256 $ 23,776 $ 40,569 $ 127,914
1 Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report. 45 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC45
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

3. CAPITAL ASSETS
The following is a summary of changes in utility plant and lease and subscription assets during the fiscal years ended June 30, 2023 and 2022:

Balance
As of
6/30/2021 Additions
Retirements/
Transfers
Balance
As of
6/30/2022 Additions
Retirements/
Transfers
Balance
As of
6/30/2023
Production $ 269,248 $ 566 $ - $ 269,814 $ 119 $ (3,967) $ 265,966 Transmission 49,079 1,338 - 50,417 2,999 - 53,416
Distribution 706,807 22,300 (3,948) 725,159 21,894 (5,176) 741,877 General 117,696 6,159 (423) 123,432 3,487 (4,792) 122,127 Intangibles 21,986 3,977 - 25,963 704 - 26,667
Depreciable utility plant 1,164,816 34,340 (4,371) 1,194,785 29,203 (13,935) 1,210,053 Less accumulated depreciation:

Production (111,878) (9,040) - (120,918) (9,032) 397 (129,553) Transmission (21,401) (972) - (22,373) (1,004) - (23,377) Distribution (302,455) (19,440) 3,917 (317,978) (20,043) 4,247 (333,774) General (54,007) (4,816) 423 (58,400) (5,272) 4,575 (59,097) Intangibles (13,347) (2,450) - (15,797) (2,838) - (18,635) Accumulated depreciation (503,088) (36,718) 4,340 (535,466) (38,189) 9,219 (564,436) Net depreciable utility plant 661,728 (2,378) (31) 659,319 (8,986) (4,716) 645,617 Land 53,042 - - 53,042 3,344 - 56,386
Intangible, non-amortizable 10,651 - - 10,651 - - 10,651 Construction in progress 72,481 32,361 (32,118) 72,724 27,125 (27,587) 72,262 Nondepreciable utility plant 136,174 32,361 (32,118) 136,417 30,469 (27,587) 139,299 Total utility plant $ 797,902 $ 29,983 $ (32,149) $ 795,736 $ 21,483 $ (32,303) $ 784,916 Lease and subscription assets, being amortized:1
Building - intangible $ - $ 348 $ - $ 348 $ - $ - $ 348 Machinery and equipment - intangible - 280 - 280 - - 280 Subscription-based information technology
arrangements - - - - 128 (35) 93
Total lease and subscription assets - 628 - 628 - - 721 Less lease accumulated amortization:

Machinery and equipment - intangible - (62) - 62 (62) - (124) Building - intangible - (75) - 75 (74) - (149)
Subscription-based information technology
arrangements - - - - (78) 35 (43)
Total lease accumulated amortization - (137) - (137) (214) - (316) Total lease and subscription assets, net $ - $ 491 $ - $ 491 $ (86) $ - $ 405 Total capital assets being depreciated,
net $ 797,902 $ 30,474 $ (32,149) $ 796,227 $ 21,397 $ (32,303) $ 785,321 1 GASB 87 Leases was implemented effective July 1, 2021. GASB 96 Subscription-Based Information Technology Arrangements (SBITA) was implemented effective July 1, 2022. For additional information, refer to Notes 1 and 14. 46 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS
The following is a summary of changes in long-term obligations during the fiscal years ended June 30, 2023 and 2022 (in thousands):

Balance
As of
6/30/2021 Additions Reductions
Balance
As of
6/30/2022 Additions Reductions
Balance
As of
6/30/2023
Due Within
One Year
Revenue bonds $ 587,822 $ - $ (18,637) $ 569,185 $ - $ (19,358) $ 549,827 $ 17,515 Pension obligation bonds 70,951 - (3,310) 67,641 - (4,233) 63,408 5,118 Direct borrowings:

Financed purchases 909 - (545) 364 - (364) - -
Total long-term obligations $ 659,682 $ - $ (22,492) $ 637,190 $ - $ (23,955) $ 613,235 $ 22,633 Long-term debt consists of the following (in thousands):

Pension Obligation Bonds Payable
June 30, 2023 June 30, 2022
$31,960 2017 Taxable Pension Obligation Bonds Series A: fixed rate bonds issued by the City due in annual installments from $2,910 to $3,580 through June 2027, with coupons from 1.3 to 3.1 percent. The Electric Utility's proportional share of the outstanding debt is 29.4 percent.
$ 4,065 $ 5,014
$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 $14,625 through June 2045, with coupons from 1.6 to 3.9 percent. The Electric Utility's proportional share of the outstanding debt is 32.9 percent. 59,343 62,627
Total pension obligation bonds payable 63,408 67,641
47 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC47
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)
Revenue Bonds Payable
June 30, 2023 June 30, 2022
$141,840 2008 Electric Refunding/Revenue Bonds:

A - $84,515 2008 Series A Bonds - variable rate bonds due in annual principal installments from $4,575 to $7,835 through October 1, 2029. Interest rate is subject to weekly repricing (net interest rate, including swaps, at June 30, 2023 was 3.0 percent). Partially refunded $13,975 on July 25, 2013 with the 2013 Electric Revenue Refunding Bonds. Partially refunded $31,500 on April 1, 2019 with 2019A Electric Refunding Bonds.
$ 34,465 $ 34,465
C - $57,325 2008 Series C Bonds - variable rate bonds due in annual principal installments from $700 to $5,200 through October 1, 2035. Interest rate is subject to weekly repricing (net interest rate, including swaps, at June 30, 2023 was 3.1 percent). Partially refunded $11,775 on July 25, 2013 with the 2013 Electric Revenue Refunding Bonds. Partially refunded $8,925 on April 1, 2019 with 2019A Electric Refunding Bonds.
32,150 32,150
$133,290 2010 Electric Revenue Series A Bonds: fixed rate, federally taxable Build America Bonds due in annual principal installments from $2,300 to $33,725, through October 1, 2040, interest from 3.9 to 4.9 percent 126,110 128,600
$56,450 2011 Electric Revenue/Refunding Series A Bonds: fixed rate bonds due in annual principal installments from $725 to $5,175 through October 1, 2035, interest of 3.2 percent
33,600 35,550
$79,080 2013 Electric Revenue Refunding Series A Bonds: fixed rate bonds due in annual principal installments from $795 to $2,625 through October 1, 2043, interest from 3.0 to 5.25 percent
35,385 36,355
$283,325 2019 Electric Revenue Refunding Series A Bonds: fixed rate bonds due in annual principal installments from $3,545 to $24,005 through October 1, 2048, interest of 5.0 percent
245,660 257,010
Total electric revenue bonds payable 507,370 524,130
Total electric revenue and pension obligation bonds payable 570,778 591,771 Unamortized bond premium 42,457 45,055
Total electric revenue and pension obligation bonds payable, including bond premium
613,235 636,826
Less current portion of revenue and pension obligation bonds payable (22,633) (20,992) Total long-term electric revenue and pension obligation bonds payable $ 590,602 $ 615,834 The Electric Utility is obligated to pay its share of the City’s pension obligation bonds, which the 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 bonds were issued to reduce the City’s unfunded pension liability in both the City’s Miscellaneous and Safety CalPERS plans. It is estimated 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 are due in annual installments from $1,285 to $14,625 through June 2045, with coupons from 1.6 to 3.9 percent. The Electric Utility's proportional share of the miscellaneous plan is 32.9 percent.

The Electric Utility’s proportional share of the outstanding principal amount of the bonds was $63,408 and $67,641 as of June 30, 2023 and 2022, respectively. The bond proceeds were deposited with CalPERS to fund the unfunded actuarial accrued liability for non-safety employees. For more discussion relating to the City’s pension obligation bond issuance, see the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report for the fiscal year ended June 30, 2023.
48 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)
Remaining pension obligation bond debt service payments will be made from revenues of the Electric Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Fiscal Year Principal Interest Total
2024 $ 5,118 $ 2,044 $ 7,162
2025 5,675 1,930 7,605
2026 5,839 1,797 7,636
2027 5,596 1,646 7,242
2028 3,800 1,493 5,293
2029-2033 13,766 6,109 19,875
2034-2038 15,507 3,320 18,827
2029-2043 8,107 723 8,830
Total $ 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% in aggregate amount of Bond Obligation may, by written notice to the City, declare the entire unpaid principal and accreted value of the bonds due and payable should the City fail to pay its debts as they become due or upon the entry of any decree or order of bankruptcy of the City.

Remaining revenue bond debt service payments will be made from revenues of the Electric Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Fiscal Year Principal Interest Total
2024 $ 17,515 $ 23,362 $ 40,877
2025 18,335 22,488 40,823
2026 19,305 21,580 40,885
2027 20,085 20,742 40,827
2028 20,960 19,864 40,824
2029-2033 118,900 84,562 203,462
2034-2038 138,570 55,605 194,175
2039-2043 121,770 19,283 141,053
2044-2048 26,430 4,532 30,962
2049-2053 5,500 138 5,638
Premium 42,457 - 42,457
Total $ 549,827 $ 272,156 $ 821,983
The Electric Utility has a number of debt issuances (revenue bonds) outstanding that are collateralized by the pledging of electric revenues. The amount and term of the remainder of these commitments are indicated in the revenue bonds payable and annual debt service requirements to maturity tables presented within this Note 4. The purpose of the debt issuances was for the financing of various Electric Utility capital improvement projects. For June 30, 2023 and 2022, debt service payments as a percentage of the pledged gross revenue, net of certain expenses where so required by the debt agreement, are indicated in the table below. The debt service coverage ratios also approximate the relationship of the debt service to pledged revenue for the remainder of the term of the commitment.

Fiscal Year Ended
Description of
Pledged Revenues
Annual Amount of
Pledged Revenue
(net of expenses) 1,2, 3
Annual Debt Service
Payments
Debt Service
Coverage
Ratio
June 30, 2023 Electric revenues $ 93,040 $ 46,400 2.01
June 30, 2022 Electric revenues $ 93,639 $ 46,028 2.03
1Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of $(1,308) and $(16,425) for June 30, 2023 and 2022, respectively.
2Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $431 and $530 for June 30, 2023 and 2022, respectively.
3Includes GASB 87 Leases net revenue adjustment of $247 and $134 for June 30, 2023 and 2022, respectively. 49 ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

Remaining revenue bond debt service payments will be made from revenues of the Electric Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

Remaining revenue bond debt service payments will be made from revenues of the Electric Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

Remaining revenue bond debt service payments will be made from revenues of the Electric Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

Remaining revenue bond debt service payments will be made from revenues of the Electric Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

LINE OF CREDIT
On 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 Electric and Water Utility Five-Year Rate Plan to manage rate increases by enabling the Electric Utility to reduce cash levels while maintaining compliance with the Riverside Public Utilities Cash Reserve Policy. Under the terms and conditions of the agreement, the City may borrow up to $35,000 for purposes of the capital or operating financial needs of the Electric System. There were no borrowings against the line as of June 30, 2023.

LETTERS OF CREDIT
The Electric Utility’s 2008 Electric Revenue Bonds (Series A and C) and 2011 Electric Revenue Bonds (Series A) require an additional layer of security between the Electric Utility and the purchaser of the bonds. The Electric Utility has entered into the following letters of credit (LOC) in order to provide liquidity should all or a portion of the debt be optionally tendered to the remarketer without being successfully remarketed:

Debt Issue LOC Provider
LOC
Expiration
Date
2008 Electric Refunding/Revenue Bonds Series A Barclays Bank, PLC 2024 2008 Electric Refunding/Revenue Bonds Series C Barclays Bank, PLC 2024 2011 Electric Refunding/Revenue Bonds Series A Bank of America, N.A. 2026 Debt Issue
Annual
Commitment
Fee
2008 Electric Refunding/Revenue Bonds Series A %0.395
2008 Electric Refunding/Revenue Bonds Series C %0.395
2011 Electric Refunding/Revenue Bonds Series A %0.350
To the extent that remarketing proceeds are insufficient or not available, tendered amounts will be paid from drawings made under an irrevocable direct-pay letter of credit.

Liquidity advances drawn against the LOCs that are not repaid will be converted to an installment loan with principal to be paid quarterly not to exceed a 5-year period for the 2008A and 2008C bonds not to exceed a 3-year period for the 2011A bonds. For the 2008A and 2008C Bonds, the Electric Utility would be required to pay annual interest equal to the Base Rate plus 2 percent, where the Base Rate is the highest of 8 percent, the Prime Rate plus 2.5 percent, the Federal Funds Rate plus 2.5 percent and 150 percent of the yield on the 30-year U.S. Treasury Bond. For the 2011A Bonds, the Electric Utility would be required to pay annual interest equal to the Base Rate plus 2 percent, where the Base Rate is the highest of 10.5 percent, the Prime Rate plus 1 percent and the Federal Funds Rate plus 2 percent. No amounts have ever been drawn against the three LOCs due to a failed remarketing.

The various indentures allow the Electric Utility to convert the mode of the debt in the case of a failed remarketing.

INTEREST RATE SWAPS ON REVENUE BONDS
The Electric Utility has three cash flow hedging derivative instruments, which are 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 is included as part of the deferred loss on refunding associated with the new bonds. The swaps were also employed as a hedge against the new debt. Hedge accounting was applied to that portion of the hedging relationship, which was determined to be effective. The negative fair value of the interest rate swaps related to the new hedging relationship has been recorded and deferred on the Statements of Net Position.
50 ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

LINE OF CREDIT
On February 1, 2019, the City entered into a subordinate line of credit agreement with U.S. Bank, National Association.

The various indentures allow the Electric Utility to convert the mode of the debt in the case of a failed remarketing.

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

LINE OF CREDIT
On February 1, 2019, the City entered into a subordinate line of credit agreement with U.S. Bank, National Association.

The various indentures allow the Electric Utility to convert the mode of the debt in the case of a failed remarketing.

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 is as follows:

Outstanding
Notional
Amount
Fair Value
as of
June 30, 2023
Change in
Fair Value
for Fiscal Year
2008 Electric Refunding/Revenue Bonds Series A $ 34,465 $ (491) $ 1,394 2008 Electric Refunding/Revenue Bonds Series C $ 32,150 $ (1,809) $ 1,686 2011 Electric Refunding/Revenue Bonds Series A $ 33,600 $ (1,797) $ 1,728 Objective: In order to lower borrowing costs as compared to fixed-rate bonds, the Electric Utility entered into interest rate swap agreements in connection with its $141,840 2008 Electric Refunding/Revenue Bonds (Series A and C) and $56,450 2011 (Series A).

Terms: Per the existing swap agreements, the Electric Utility pays the counterparty a fixed payment and receives a variable payment computed as 62.68 percent of the London Interbank Offering Rate (“LIBOR”) one month index plus 12 basis points. The swaps have notional amounts equal to the principal amounts stated above. The notional value of the swaps and the principal amounts of the associated debt decline by $6,000 to $7,835 (2008 Series A), $700 to $5,200 (2008 Series C) and $725 to $5,175 (2011 Series A) until the debt is completely retired in fiscal years 2030 (2008 Series A) and 2036 (2008 Series C and 2011 Series A).

The bonds and the related swap agreements for the Electric Refunding/Revenue 2008 (Series A) Bonds mature on October 1, 2029 and the 2008 (Series C) and 2011 (Series A) Bonds mature on October 1, 2035. As of June 30, 2023 rates were as follows:
2008 Electric
Refunding/Revenue
Series A Bonds
2008 Electric
Refunding/Revenue
Series C Bonds
2011 Electric
Refunding/Revenue
Series A Bonds
Interest rate swap: Terms Rates Rates Rates
Fixed payment to counterparty Fixed %3.11100 %3.20400 %3.20100 Variable payment from counterparty 62.68 LIBOR + %(0.69885) %(0.69911) %(0.75953) Net interest rate swap payments 12bps %2.41215 %2.50489 %2.44147 Variable-rate bond coupon payments %0.56351 %0.57077 %0.68005 Synthetic interest rate on bonds %2.97566 %3.07660 %3.12152 Fair 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 adjust to changing interest rates, the bonds do not have a corresponding fair value decrease. The fair value was developed by a pricing service using the zero-coupon method. This method calculates the future net settlement payments required by the swaps, assuming that the current forward rates implied by the yield curve correctly anticipate future spot interest rates. These payments are then discounted using the spot rates implied by the current yield curve for hypothetical zero-coupon bonds due on the date of each future net 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 fair value. 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 require the fair value of the swaps to be collateralized by the counterparty with U.S. Government securities if the counterparties’ rating decreases to negotiated trigger points. Collateral would be posted with a third-party custodian. At June 30, 2023, there is no requirement for collateral posting for any of the outstanding swaps.

Basis risk: As noted above, the swaps expose the Electric Utility to basis risk should the relationship between LIBOR and the variable interest rates converge, changing the synthetic rate on the bonds. If a change occurs that results in the rates moving to convergence, the expected cost savings may not be realized.

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)
credit quality falls below “BBB-” as issued by S&P. The Electric Utility or the counterparty may terminate a swap if the other party fails to perform under the terms of the contract. If a swap is terminated, the variable-rate bond would no longer carry a synthetic interest rate. Also, if at the time of termination, a swap has a negative fair value, the Electric Utility would be 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 and net swap payments, assuming current interest rates remain the same for their term, are summarized in the table below. As rates vary, variable-rate bond interest payments and net swap payments will vary.

Variable-Rate Bonds
Fiscal Year
Ending
June 30, Principal Interest
Interest Rate
Swaps, Net Total
2024 $ 725 $ 671 $ 2,703 $ 4,099
2025 725 665 2,681 4,071
2026 1,450 629 2,532 4,611
2027 7,425 582 2,331 10,338
2028 7,885 531 2,121 10,537
2029-2033 51,980 1,795 7,059 60,834
2034-2038 30,025 274 1,075 31,374
Total $ 100,215 $ 5,147 $ 20,502 $ 125,864
Replacement of London Interbank Offering Rate (LIBOR): As of July 1, 2023, LIBOR is no longer an appropriate benchmark interest rate for a derivative instrument that hedges the interest risk for taxable debt for purposes of GASB Statement 53.

FINANCED PURCHASES
The Electric Utility has entered into sixteen purchase agreements for financing sixteen compressed natural gas heavy duty service trucks. All agreements have seven-year terms of monthly payments with interest rates ranging from 2.0 percent to

2.5 percent. 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, 2022 the total liability was $364. The final payment on this agreement was made in February 2023, which consisted of $364 principal and $2 interest. No further payments are due.

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probable that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in Compensated absences for the Electric Utility during the fiscal year.

Balance
As of
6/30/2021 Additions Reductions
Balance
As of
6/30/2022 Additions Reductions
Balance
As of
6/30/2023
Due Within One
Year
Compensated absences $ 7,182 $ 4,780 $ (4,762) $ 7,200 $ 5,659 $ (5,381) $ 7,478 $ 5,589 52 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN

PLAN DESCRIPTION
The City contributes to CalPERS, an agent multiple employer 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 and administrative agent for participating public entities within the State of California. CalPERS issues a publicly available financial report that includes financial statements and required supplementary information for the cost sharing plans that are administered by CalPERS. Benefit provisions and all other requirements are established by state statute and City ordinance. A copy of CalPERS’ annual financial report may be obtained online at www.calpersca.gov. The Electric Utility participates in the City’s Miscellaneous (non-safety) Plan (the Plan).

FUNDING POLICY
The City has contributed at the actuarially determined rate provided by CalPERS’ actuaries. Participants are required to contribute 8% of their annual covered salary. The City has a multiple tier retirement plan with benefits varying by plan. All permanent full-time and selected part-time employees are eligible for participation in CalPERS. Benefits vest after five years of service and are determined by a formula that considers the employee’s age, years of service and salary. Under the Plan, the City pays the employees’ contribution to CalPERS for employees hired on or before specific dates as follows:
 1st Tier –
 The retirement formula is 2.7% at age 55 for employees hired on or before October 18, 2011. Effective January 1, 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 employees were required to pay 2% of their pensionable income, with the City contributing the other 6%. Effective January 1, 2019, employees were required to pay an additional portion of their pensionable income. This portion was a three-year increase of 2% (2019), 2% (2020) and 2% (2021). As of 2021, 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 other 1%. Effective January 1, 2019, employees were required to pay an additional portion of their pensionable income. This portion was a two-year increase of 1% (2019) and 1% (2020). As of 2020, employees are contributing 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 before October 18, 2011. Effective November 1, 2017, employees were required to pay 2% of their total pensionable income with the City paying the remaining 6%. Effective each November 1st, employees were required to pay an 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 pensionable income.
 2nd Tier –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 the employee must pay the normal cost to CalPERS, which is currently at 7.75%. Classic members (CalPERS members 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. 53 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC53
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

BENEFITS PROVIDED
CalPERS provides service retirement and disability benefits, annual cost-of-living adjustments and death benefits to plan members who must be public employees and beneficiaries. Benefits are based on years of credited service, equal to one year of full-time employment. Members with five years of total service are eligible to retire at age 50 with statutorily reduced benefits. All members are eligible for non-duty disability benefits after five years of service. The death benefit is one of the following: the Basic Death Benefit, the 1959 Survivor Benefit Level III, or the Optional Settlement 2W Death Benefit. The cost-of-living adjustments for the Plan are applied as specified by the Public Employees’ Retirement Law.

EMPLOYEES COVERED
As of measurement date June 30, 2022 and 2021, the following employees, City-wide, were covered by the benefit terms of the Plan:

Measurement Date
June 30, 2022 June 30, 2021
Inactive employees or beneficiaries
currently receiving benefits 2,418 2,373
Inactive employees entitled to but not
yet receiving benefits 1,475 1,422
Active employees 1,527 1,508

CONTRIBUTIONS
Section 20814(c) of the California Public Employees’ Retirement Law requires that the employer contribution rates for all public employers be determined on an annual basis by the actuary and shall be effective on the July 1 following notice of a change in the rate. Funding contributions for the Plan is determined annually on an actuarial basis as of June 30 by CalPERS. The actuarially determined rate is the estimated amount necessary to finance the costs of benefits earned by employees during the year, with an additional amount to finance any unfunded accrued liability. The City is required to contribute the difference between the actuarially determined rate and the contribution rate of employees.

NET PENSION LIABILITY
The City’s net pension liability for the Plan is measured as the total pension liability, less the pension plan’s fiduciary net position. For fiscal year ended June 30, 2023, the net pension liability of the Plan is measured as of June 30, 2022, using an annual actuarial valuation as of June 30, 2021 rolled forward to June 30, 2022 using standard update procedures. For fiscal year ended June 30, 2022 , the net pension liability of the Plan is measured as of June 30, 2021 , using an annual actuarial valuation as of June 30, 2020 rolled forward to June 30, 2021 using standard update procedures. A summary of principal assumptions and methods used to determine the net pension liability is shown below:

ACTUARIAL ASSUMPTIONS
The total pension liabilities in the June 30, 2022 and 2021 actuarial valuations were determined using the following actuarial assumptions:
54 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

ACTUARIAL ASSUMPTIONS (CONTINUED)
Miscellaneous - Current Year Miscellaneous - Prior Year Valuation Date June 30, 2021 June 30, 2020
Measurement Date June 30, 2022 June 30, 2021
Actuarial Cost Method Entry-Age Normal Cost Method Entry-Age Normal Cost Method Actuarial Assumptions
Discount Rate 6.90% 7.15%
Inflation 2.30% 2.50%
Salary Increase Varies by entry age and service Varies by entry age and service Mortality Rate Table1 Derived using CalPERS’ membership data for all funds.

Post Retirement Benefit
Increase
The lesser of contract COLA or 2.30% until
Purchasing Power Protection Allowance floor
on purchasing power applies, 2.30%
thereafter
The lesser of contract COLA or 2.50% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.50%
thereafter
1The 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 from 2001 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 the CalPERS website.

LONG-TERM EXPECTED RATE OF RETURN
The long-term expected rate of return on pension plan investments was determined using a building-block method in expected future real rates of return (expected returns, net of pension plan investment expense and inflation) are developed for 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, expected compound (geometric) returns were calculated over the next 20 years using a buildingblock approach. The expected rate of return was then adjusted to account for assumed administrative expenses of 10 Basis points. The expected real rates of return by asset class are as follows:

June 30, 2022 Measurement Date
Asset Class(1)
Assumed Asset
Allocation Real Return(1),(2)
Global Equity - Cap-weighted 30.00% 4.54%
Global Equity - Non-Cap-weighted 12.00% 3.84%
Private Equity 13.00% 7.28%
Treasury 5.00% 0.27%
Mortgage-backed Securities 5.00% 0.50%
Investment Grade Corporates 10.00% 1.56%
High Yield 5.00% 2.27%
Emerging Market Debt 5.00% 2.48%
Private Debt 5.00% 3.57%
Real Assets 15.00% 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. 55 ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

LONG-TERM EXPECTED RATE OF RETURN (CONTINUED)
June 30, 2021 Measurement Date
Asset Class(1)
Current Target
Allocation
Real Return
Years 1 - 10(2)
Global Equity 50.00% 4.80%
Fixed Income 28.00% 1.00%
Inflation Assets 0.00% 0.77%
Private Equity 8.00% 6.30%
Real Assets 13.00% 3.75%
Liquidity 1.00% 0.00%
June 30, 2021 Measurement Date
Asset Class(1)
Real Return
Years 11+(3)
Global Equity 5.98%
Fixed Income 2.62%
Inflation Assets 1.81%
Private Equity 7.23%
Real Assets 4.93%
Liquidity -0.92%
(1) In the System's ACFR, Fixed Income is included in Global Debt Securities; Liquidity is included in Short-term Investments; Inflation Assets are included in both Global Equity Securities and Global Debt Securities. (2) An expected inflation of 2.00% used for this period. (3) An expected inflation of 2.92% used for this period.

DISCOUNT RATE
The discount rate used to measure the total pension liability was 6.90% and 7.15% for measurement dates as of June 30, 2022 and 2021, respectively. The projection of cash flows used to determine the discount rate assumed that contributions from plan members will be made at the current member contribution rates and that contributions from employers will be made at statutorily required rates, actuarially determined. Based on those assumptions, the Plan’s fiduciary net position was 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 the total pension liability.

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

7.15% to 6.90%. In determining the long-term expected rate of return, CalPERS took into account long-term market return expectations as well as the expected pension fund cash flows. Projected returns for all asset classes are estimated, combined with risk estimates, and are used to project compound (geometric) returns over the long term. The discount rate used to discount liabilities was informed by the long-term projected portfolio return. In addition, demographic assumptions and the inflation rate assumption were changed in accordance with the 2021 CalPERS Experience Study and Review of Actuarial Assumptions.

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, 2023 (measurement date June 30, 2022) and 2022 (measurement date June 30, 2021) for the Plan are as follows:
56 ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

CHANGES IN THE NET PENSION LIABILITY (ASSET) (CONTINUED) June 30, 2023
Net Pension
Liability/
(Asset)
Proportion of
the Plan
Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022) $ 38,748 %29.42 Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) (26,219) %29.56 Changes - Increase / (Decrease) 64,967 %(0.14)
June 30, 2022
Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) (26,219) %29.56 Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 39,233 %32.68 Changes - Increase / (Decrease) (65,452) %(3.11)

PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO

PENSION
For the fiscal years ended June 30, 2023 and 2022, the Electric Utility recognized pension expense of $7,266 and $(8,343), respectively. At June 30, 2023 and 2022, the Electric Utility reported deferred outflows of resources and deferred inflows of resources related to pension from the following sources:

June 30, 2023 June 30, 2022
Deferred
Outflows of
Resources
Deferred
Inflows of
Resources
Deferred
Outflows of
Resources
Deferred
Inflows of
Resources
Pension contribution subsequent to the
measurement date $ 8,574 $ - $ 8,080 $ -
Changes in Assumptions 3,982 - - -
Difference between expected and actual
experience 263 (3,577) 1,088 -
Net difference between projected and
actual earnings on pension plan
investments 22,112 - - (44,089)
Total $ 34,931 $ (3,577) $ 9,168 $ (44,089)
Deferred outflows of resources related to contributions subsequent to the measurement date reported in prior year was recognized as a reduction of the net pension liability in the year ended June 30, 2022.

The remaining amounts reported as deferred outflows of resources and deferred (inflows) of resources related to pensions will be recognized as pension expense as follows:

Year Ended
June 30
Deferred Outflows/
(Inflows) of
Resources
2024 $ 4,049
2025 3,471
2026 1,500
2027 13,760
Total $ 22,780
57 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC57
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO

PENSION (CONTINUED)
Subsequent Events - On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for fiscal year 2020-21. Based on the thresholds specified in CalPERS Funding Risk Mitigation policy, the excess return of 14.3% prescribes a reduction in investment 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 board elected to defer any changes to the asset allocation until the ALM process concluded, and the board could make its final decision 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 new capital market assumptions, economic assumptions and administrative expense assumption support a discount rate of

6.90% (net of investment expense but without a reduction for administrative expense) for financial reporting purposes. This includes a reduction in the price inflation assumption from 2.50% to 2.30% as recommended in the November 2021 CalPERS Experience Study and Review of Actuarial Assumptions. This study also recommended modifications to retirement rates, termination rates, mortality rates and rates of salary increases that were adopted by the board. These new assumptions will be reflected in the GASB 68 accounting valuation reports for the June 30, 2022, measurement date.

SENSITIVITY OF THE NET PENSION LIABILITY (ASSET) TO CHANGES IN THE DISCOUNT RATE The following presents the Electric Utility’s proportionate share of the net pension liability of the Plan, calculated using the discount rate of 6.90% (measurement date June 30, 2022) and 7.15% (measurement date June 30, 2021), as well as what the Electric Utility’s proportionate share of the net pension 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 Date
June 30, 2022
Measurement Date
June 30, 2021
Discount Rate
-1%
(5.90%)
Current
Discount Rate
(6.90%)
Discount Rate
+1%
(7.90%)
Discount Rate
-1%
(6.15%)
Current
Discount Rate
(7.15%)
Discount Rate
+1%
(8.15%)
Electric Utilitiy's
proportionate share of the
Plan's net pension liability
$ 103,174 $ 38,748 $ (14,155) $ 35,141 $ (26,219) $ (76,749) Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports. 58 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB)

PLAN DESCRIPTION
The City’s defined benefit OPEB plan, Retiree Health Plan, provides continuation of medical (including prescription drugs) and dental coverage benefits to retirees and surviving spouses in the form of an implied rate subsidy. The Retiree Health Benefits plan is a single employer defined benefit OPEB plan administered by the City. No assets are accumulated in a trust that meets the criteria in paragraph 4 of GASB Statement No. 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 both the active and retired employees. The City is not required by law or contractual agreement to provide funding other than the pay-as-you-go amount necessary to provide current benefits to eligible retirees and beneficiaries. Retiree and spousal coverage terminate when the retiree becomes covered under another employer health plan, or when the retiree reaches Medicare eligibility age, which is currently age 65. However, retiree benefits continue to the surviving spouse if the retiree elects the CalPERS survivor annuity.

As of measurement date June 30, 2022 and 2021, the following employees, City-wide, were covered by the benefit terms:

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
Inactive plan members or beneficiaries
currently receiving benefits 206 206
Inactive plan members entitled to but
not yet receiving benefits - -
Active plan members 2,014 2,014
59 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC59
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

ACTUARIAL ASSUMPTIONS
The total OPEB liability was determined by actuarial valuation as of June 30, 2022 and 2021 using the following actuarial assumptions:

Miscellaneous - Current Year Miscellaneous - Prior Year Valuation Date June 30, 2021 June 30, 2021
Measurement Date June 30, 2022 June 30, 2021
Actuarial Cost Method Pay-as-you-go for implicit rate subsidy Pay-as-you-go for implicit rate subsidy Actuarial Assumptions
Discount Rate Bond Buyer 20 Index at June 30, 2022
resulting in a rate of 3.54%
Bond Buyer 20 Index at June 30, 2021
resulting in a rate of 2.16%
Inflation Rate 2.50% per annum 2.75% per annum
Payroll Increases 2.75% per year. Since benefits do not depend on salary (as they do for pensions), this
assumption is only used to determine the
accrual pattern of the Actuarial Present Value
of Projected Benefit Payments.

2.75% per year. Since benefits do not
depend on salary (as they do for pensions),
this assumption is only used to determine
the accrual pattern of the Actuarial Present
Value of Projected Benefit Payments.

Mortality 2017 CalPERS Retiree Mortality Table for the
appropriated population
2017 CalPERS Retiree Mortality Table for
the appropriated population
Healthcare Trend Medical trend in future years has been Medical trend in future years has been Rates updated to 4.00% for all years from 6.25% updated to 4.00% for all years from 6.25% tiered down by 0.25% per year to 4.50% in all
future years.
tiered down by 0.25% per year to 4.50% in
all future years.

CHANGES OF ASSUMPTIONS
In 2022, the discount rate was changed from 2.16% to 3.54%.

SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN HEALTHCARE COST TREND RATES The following presents the Electric Utility’s proportionate share of the City’s total OPEB liability, calculated using the healthcare trend rate of 4.00% for the measurement date as of June 30, 2022 and 2021, as well as what the Electric Utility’s total OPEB liability would be if it was calculated using a healthcare cost trend rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
Current
healthcare cost
trend rate 4% 1% Increase 1% Decrease
Current
healthcare cost
trend rate 4% 1% Increase
Electric Utility's proportionate
share of the
total OPEB liability $ 8,627 $ 9,837 $ 11,213 $ 9,205 $ 10,460 $ 11,950 60 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN DISCOUNT RATES The following presents the Electric Utility’s proportionate share of the City's total OPEB liability, calculated using the discount rate of 3.54% and 2.16% for measurement dates of June 30, 2022 and 2021 respectively, as well as what the Electric 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 Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Electric Utility's
proportionate share of the
total OPEB liability $ 10,782 $ 9,837 $ 9,169 $ 11,354 $ 10,460 $ 9,632

CHANGE IN TOTAL OPEB LIABILITY
For fiscal years ended June 30, 2023 and 2022, the Electric Utility recognized total OPEB expense of $431 and $530 respectively. The following table shows the change in the Electric Utility’s proportionate share of the City’s total OPEB liability for the year ended June 30, 2023 (measurement date June 30, 2022) and the year ended June 30, 2022 (measurement date June 30, 2021):

June 30, 2023
Net OPEB
Liability
Proportion of
the Plan
Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022) $ 9,837 %21.63 Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) 10,460 %21.45 Changes - Increase / (Decrease) (623) %0.18
June 30, 2022
Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) 10,460 %24.45 Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 11,126 %24.28 Changes - Increase / (Decrease) (666) %0.17

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Electric Utility reported deferred inflows of resources related to OPEB from the following sources:

Deferred Outflows
of Resources
Deferred Inflows of
Resources
Difference between expected and
actual experience $ 29 $ (649)
Changes of assumptions 1,254 (1,617)
Contributions subsequent to
measurement date 309 -
Total $ 1,592 $ (2,266)
61 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC61
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB (CONTINUED) Amounts reported as deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:

Year Ended
June 30
Deferred Outflows/
(Inflows) of
Resources
2024 $ (27)
2025 (27)
2026 15
2027 22
2028 22
Thereafter (988)
Total $ (983)

8. RESTRICTED NET POSITION
The California Code of Regulations establishes a restriction on the use of proceeds obtained from the sale of greenhouse gas allowances at auctions held pursuant to California’s Cap-and-Trade Program. The proceeds are to be used exclusively for the benefit of retail ratepayers of each electrical distribution utility and may not be used for the benefit of entities or persons other than such ratepayers. In addition, the Low Carbon Fuel Standard Program (LCFS) was established and restricts the use of the proceeds obtained from the sale of LCFS credits. The available funds are to be utilized for qualifying 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 net position. 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 and reserving a portion of net position. Bond indentures for the Electric Utility’s electric revenue and refunding bonds require debt service reserves that equate to the maximum annual debt service required in future years and bond service reserves of three months interest and nine months principal due in the next fiscal year. Variable rate revenue and refunding bonds require 110 percent of the monthly accrued interest to be included in the reserve. Active electric revenue bonds requiring reserves are issues 2008A & C and certain issues have no debt service reserve requirements (2010A, 2011A, 2013A and 2019A).
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9. JOINTLY-GOVERNED ORGANIZATIONS

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
On 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 was admitted 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 fiscal years ended June 30, 2023 and 2022, the Electric Utility paid approximately $21,085 and $21,549, respectively, to SCPPA under various take-or-pay and renewable contracts that are described in greater detail in Note 11. These payments are reflected as a component of production and purchased power and transmission expenses in the financial statements.

POWER AGENCY OF CALIFORNIA
On 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 cities acting in concert. PAC has the ability to plan, finance, develop, acquire, construct, operate and maintain projects for the generation and transmission of electric energy for sale to its participants. PAC is governed by a Board of Directors, which consists of one representative from each of the members. The term of the Joint Powers Agreement is 50 years. Effective June 30, 2001, PAC was placed in an inactive status by the Board of Directors. The Agency can only be reactivated by authorization of the Agency Board.
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10. JOINTLY-OWNED UTILITY PROJECT - SONGS
The City has a 1.79 percent undivided ownership interest in Units 2 and 3 of SONGS, located south of the City of San Clemente 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 its costs, 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 of Anaheim 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 in Units 2 and 3 at SONGS and remove and dispose of the predecessor generators. SCE completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively. The Electric Utility’s share of the cost to replace the steam generators was approximately $13.4 million. Replacement of the steam generators was expected to enable plant operations 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 shut down. At that time, Unit 2 was off-line for a planned outage when unexpected wear in areas of tube-to-support structure were found. Units 2 and 3 remained off-line for extensive inspections, testing and analysis of their steam generators. On June 7, 2013, SCE unilaterally announced its plan to retire Units 2 and 3 permanently.

Nuclear Decommissioning. As a result of SCE’s decision to permanently retire SONGS Units 2 and 3, the decommissioning phase of the plant began in June 2013. The process of decommissioning the nuclear power plant is expected to take many years and is governed by NRC regulations. According to SCE’s decommissioning cost estimate document 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 the update, 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.

Nuclear Decommissioning Funding and Liability. As of June 30, 2023, the Electric Utility has set aside $47,110 in cash investments with the trustee and $8,644 in a designated decommissioning reserve for the Electric Utility’s estimated share of the decommissioning costs. Increases to the funds held for decommissioning liability are from investment earnings. The investment earnings are included in investment income in the Electric Utility’s financial statements. An equivalent 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 decommissioning costs invoiced by SCE.

On February 23, 2016, the City Council adopted a resolution authorizing the commencement of SONGS decommissioning effective June 7, 2013. This resolution allows the Electric Utility to access the decommissioning trust funds to pay for its share of decommissioning costs. The Electric Utility began drawing decommissioning trust funds to pay for decommissioning costs in the fiscal year ended June 30, 2017. As of June 30, 2023 , the Electric Utility has paid to date $45,884 in decommissioning obligations, which have been reimbursed by the trust funds.

As of June 30, 2023 and 2022, decommissioning liability balance was $48,873 and $53,310, respectively, with a portion reflected as current liabilities payable from restricted assets. As a result of the updated SCE decommissioning cost estimate and the increase in the Electric Utility's estimated share, the decommissioning liability was increased by $5.7 million in fiscal year 2022. The offset of this liability increase was recorded as an extraordinary item in fiscal year 2021/22.

See Note 13 for additional information.

The Electric Utility no longer provides additional funding to the trustee. However, since the decommissioning cost estimate is subject to a number of uncertainties including the cost of disposal of nuclear waste, site remediation costs, as well as a number of other assumptions and estimates, the Electric Utility will continue to set aside funds in the designated decommissioning reserve of $2,000 per year, as approved by the Board of Public Utilities and City Council.

Balance
As of
6/30/2021 Additions Reductions
Balance
As of
6/30/2022 Additions Reductions
Balance
As of
6/30/2023
Due Within One
Year
Nuclear decommissioning liability $ 50,896 $ 6,555 $ (4,141) $ 53,310 $ 907 $ (5,344) $ 48,873 $ 10,227 64 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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NOTES TO THE FINANCIAL STATEMENTS

11. COMMITMENTS
The 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 output of IPA’s 1,800 MW central Utah coal-fueled generating station, known as Intermountain Power Project (IPP). The contract expires in 2027 and the debt fully matures in 2024.

The contract constitutes an obligation of the Electric Utility to make payments solely from operating revenues. The power purchase contract requires the Electric Utility to pay certain minimum charges that are based on debt service requirements and other fixed costs. Such payments are considered a cost of production.

On September 29, 2006, Senate Bill 1368 (SB 1368) was enacted into law. The bill requires electric service providers to limit financial investments in power plants to those that adhere to greenhouse gas performance standards as determined by the Public Utilities Commission. Pursuant to this legislation, the Electric Utility is prohibited from renewing its participation in IPP 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 Sales Contract, which amended the IPP Contract allowing the plant to replace the coal units with combined cycle natural gas units by July 1, 2025. On June 16, 2015, the City Council approved the IPP renewal agreements, including the Second Amendatory Power Sales Contract and the Renewal Power Sales Contract, and authorized participation in the IPP Repower Project for up to 5 percent in generation capacity or 60 MW. The Second Amendatory Power Sales Contract became effective March 16, 2016.

On January 5, 2017, the Electric Utility executed the Renewal Power Sales Contract and the Electric Utility accepted an offer of 4.167 percent entitlement or 50 MW generation capacity in the IPP Repower Project based on the 1,200 MW designed capacity, which is within the maximum participation level approved by the City Council. The Electric Utility’s corresponding Southern Transmission System allocation is 5.278 percent or approximately 127 MW. Further, under the Renewal Power Sales Contract, the Electric Utility had the right to exit from the Repower Project by no later than November 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 reduced the 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 the Electric Utility effective November 1, 2019, and the Electric Utility’s exit from the IPP Repower Project upon the expiration date of the current Power Sales Contract on June 15, 2027, due to numerous uncertainties surrounding the IPP Repower Project.

The Electric Utility is a member of SCPPA, a joint powers agency (see Note 9). SCPPA provides for the financing and construction of electric generating and transmission projects for participation by some or all of its members. To the extent the Electric Utility participates in take-or-pay projects developed by SCPPA, it has entered into Power Purchase or Transmission 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 generation output of transmission service is available.

The projects and the Electric Utility’s proportionate share of SCPPA’s obligations, including final maturities and contract expirations are as follows:

Project Percent Share Entitlement Final Maturity Contract Expiration Palo Verde Nuclear Generating Station %5.40 12.3 MW 2017 2030 Southern Transmission System %10.20 244.0 MW 2027 2027
Mead-Phoenix Transmission %4.00 18.0 MW 2020 2030
Mead-Adelanto Transmission %13.50 118.0 MW 2020 2030
As part of the take-or-pay commitments with IPA and SCPPA, the Electric Utility has agreed to pay its share of current and long-term obligations. Management intends to pay these obligations from operating revenues received during the year that payment is due. A long-term obligation has not been recorded on the accompanying financial statements for these commitments. Take-or-pay commitments terminate upon the later of contract expiration or final maturity of outstanding bonds for each project.
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11. COMMITMENTS (CONTINUED)
The outstanding debts associated with the take-or-pay obligations have fixed interest rates, which range from 4.00 percent to 5.00 percent. The schedule below details the amount of principal and interest that is due and payable by the Electric Utility as part of the take-or-pay contract for each project in the fiscal year indicated:

IPA1 SCPPA Total
Debt Service
Payment (in thousands)
Year Ending June 30,
Intermountain
Power
Project
Southern
Transmission
System
All
Projects
2024 $ 3,479 $ 7,125 $ 10,604
2025 2,997 3,261 6,258
2026 2,997 3,257 6,254
2027 4,810 3,253 8,063
2028 - 3,254 3,254
Total $ 14,283 $ 20,150 $ 34,433
1 The Electric Utility's contract with IPA expires in 2027. The Electric Utility will not be responsible for the proportionate share of the 2022 Series A and B Revenue bonds after the contract expires.

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 facilities discussed above. These costs do not have a similar structured payment schedule as debt service varies each year. The costs incurred for the years ended June 30, 2023 and 2022, are as follows (in thousands):

Fiscal Year
Intermountain
Power
Project1
Palo Verde
Nuclear
Generating
Station1
Southern
Transmission
System
Mead-
Phoenix
Transmission
Mead-
Adelanto
Transmission
All
Projects
2023 $ 20,344 $ 3,010 $ 3,839 $ 90 $ 461 $ 27,744
2022 $ 19,522 $ 2,930 $ 4,400 $ 57 $ 415 $ 27,324
1 Excludes 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 Transmission System, Mead-Phoenix, and Mead-Adelanto Transmission Projects. In return, users of California’s high voltage transmission 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 PROJECT
The Electric Utility’s initial entitlement in the Hoover project through SCPPA terminated on September 30, 2017. On August 23, 2016, the City Council approved a 50-year Electric Service Contract (ESC) and an Amended and Restated Implementation Agreement (IA) with the Western Area Power Administration (Western) Bureau of Reclamation for 30 MW of hydroelectric power. The contract with Western is effective as of October 1, 2017. The ESC extended the Electric Utility’s 30 MW entitlement in the Hoover project through 2067. The IA is a supplemental agreement to the ESC that establishes administrative, budgetary and project oversight by creating project committees and a process for decision making in plant operations.

NUCLEAR INSURANCE
The Price-Anderson Act (the Act) requires that all utilities with nuclear generating facilities purchase the maximum private primary nuclear liability insurance available ($450 million) and participate in the industry’s secondary financial protection plan. The secondary financial protection program is the industry’s retrospective assessment plan that uses deferred premium charges from every licensed reactor owner if claims and/or costs resulting from a nuclear incident at any licensed reactor in the United States were to exceed the primary nuclear insurance at that plant’s site. Effective October 5, 2023, 66 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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11. COMMITMENTS (CONTINUED)

NUCLEAR INSURANCE (CONTINUED)
the Act limits liability from third-party claims to approximately $16.5 billion per incident. Under the industry-wide retrospective assessment program provided for under the Act, assessments are limited to $137.6 million per reactor for each 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’s interest in Palo Verde, the Electric Utility would be responsible for a maximum assessment of $1.4 million, limited to payments of $0.2 million per incident, per year. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

RENEWABLE PORTFOLIO STANDARD (RPS)
On April 12, 2011, the California Renewable Energy Resources Act (SBX1-2) was signed into law by the Governor, which officially created the first set of tiered RPS targets of 20% by 2013, 25% by 2016 and 33% by 2020. SBX1-2 specified that publicly owned utilities must meet these defined targets via interim Compliance Period (CP) targets to achieve the end goal of 33% RPS by December 31, 2020 as follows: CP1 - an average of 20 percent of retail sales during the 3-year period from 2011-2013; CP2 – no less than 25 percent of retail sales by December 31, 2016; and CP3 – no less than 33 percent of retail sales by December 31, 2020. The Riverside Public Utilities Board and City Council approved the RPS Enforcement Program required by SBX1-2 on November 18, 2011 and December 13, 2011, respectively, and further approved the Electric Utility’s RPS Procurement Plan (a.k.a. Procurement Policy) implementing the new RPS mandates on May 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 with resource procurement actions as outlined in the Electric Utility’s RPS Procurement Plan. For calendar year 2021, renewable resources provided 45 percent of retail sales requirements.

On October 7, 2015, the Governor signed into law Senate Bill 350 (SB 350) increasing the RPS mandate from 33 percent by 2020 to 50 percent by December 31, 2030. In addition, SB 350 required that an updated RPS Procurement Policy be approved and adopted before January 1, 2019 and be incorporated into the Electric Utility’s Integrated Resource Plan. An updated 2018 Renewable Energy Procurement Policy was adopted by the Board and City Council on September 10, 2018 and October 9, 2018, respectively. The Electric Utility expects to be able to substantially meet the increased RPS mandates imposed by SB 350 with the actions described in the updated procurement policy and the portfolio of renewable resources outlined below.

On September 10, 2018, the 100 Percent Clean Energy Act of 2018 (Senate Bill 100) was signed into law by the California Governor. This bill further increases the RPS goals of SBX1-2 and SB 350 while maintaining the 33 percent RPS target by December 31, 2020, but modifying the RPS percentages to be 44 percent by December 31, 2024, 52 percent by December 31, 2027, 60 percent by December 31, 2030, with an end goal of 100 percent of total retail sales of electricity in California generated from eligible renewable energy resources and zero-carbon resources by December 31, 2045. It is expected that the California Energy Commission will have further guidance and enforcement procedures for publicly owned utilities to meet these increased mandates. The Electric Utility will continue to monitor the outcome and impacts of any 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 power purchase 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. 67 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC67
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11. COMMITMENTS (CONTINUED)

RENEWABLE PORTFOLIO STANDARD (RPS) (CONTINUED)
Long-term renewable PPAs and PSAs in operation (dollars in thousands):

Supplier Type
Maximum
Contract1
Contract
Expiration
Estimated
Annual
Cost for
2023
Wintec Wind 1.3 MW 02/19/2024 $ 150
WKN Wagner Wind 6.0 MW 12/22/2032 1,358
Terraform Power - AP North Lake Photovoltaic 20.0 MW 08/11/2040 4,942 Onward Energy - Columbia II Photovoltaic 11.1 MW 12/22/2034 2,314 GlidePath Power Solutions - GPS Cabazon Wind LLC Wind 39.0 MW 01/01/2025 4,299 Capital Dynamics - Kingbird Solar B, LLC Photovoltaic 14.0 MW 12/31/2036 2,867 AES - Summer Solar Photovoltaic 10.0 MW 12/31/2041 1,748 AES - Antelope Big Sky Ranch Photovoltaic 10.0 MW 12/31/2041 1,748 AES - Antelope DSR 1 Solar Photovoltaic 25.0 MW 12/19/2036 3,826 Arevon - Tequesquite Landfill Solar Photovoltaic 7.3 MW 12/31/2040 1,434 Roseburg Forest Products2 Biomass N/A 02/16/2026 179
CalEnergy - Salton Sea Portfolio Geothermal 86.0 MW 12/31/2039 56,038 Atlantica - Coso Geothermal Geothermal 10.0 MW 12/31/2041 6,050 Total3 239.7 MW $ 86,953
1All contracts are contingent on energy delivered from specific related generating facilities. The Electric Utility has no commitment to pay any amounts except 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. 3American Renewable Power - Loyalton was excluded due to the contract expiring April 2023 and no capacity received.

Long-term renewable PPAs with expected delivery:

Supplier Type
Maximum
Contract1
Expected
Delivery
Energy Delivery No
Later Than
Contract Term In
Years
Atlantica - Coso Geothermal Geothermal 20.0 MW 01/01/2027 01/01/2027 15 Total 20.0 MW
1All contracts are contingent on energy delivered from specific related generating facilities. The Electric Utility has no commitment to pay any amounts except 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 of geothermal energy. On August 23, 2005, the City Council approved an amendment to the PPA that increased the amount of 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 additional renewable geothermal power. The PPA provides power from a portfolio of ten geothermal generating units, instead of a single generating unit, with an increasing amount of delivery that started with 20 MW in 2016, increasing to 40 MW in 2019, and 86 MW in 2020. The initial price under the agreement was $72.85 per megawatt-hour (MWh) in calendar year 2016, which will escalate at 1.5 percent annually for the remaining term of the agreement. Similar to other renewable PPAs, 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 CalEnergy through 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 Salton Sea PPA and accrual of the prepayment ended as of May 31, 2020. As of June 30, 2023 and 2022, the Electric Utility’s prepayment of future contractual obligations was $12,330 and $12,970, respectively. This prepayment is recorded on the Statements of Net Position as unamortized purchased power, to be amortized over the term of the CalEnergy PPA. The CalEnergy PPA commenced in February 2016. As of June 30, 2023 and 2022, the Electric Utility has recorded $641 and 68 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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11. COMMITMENTS (CONTINUED)

RENEWABLE PORTFOLIO STANDARD (RPS) (CONTINUED)
$645, respectively, in amortization related to the unamortized purchased power.

On January 28, 2003, the Electric Utility entered into a 15-year renewable PPA with Wintec Energy, Ltd (Wintec) to 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 amended contract with Wintec terminated in December 2018, however, on February 12, 2019, the City Council approved an extension to the amended agreement for an additional five years for a reduced price of $35.77 per MWh.

On October 16, 2012, the Electric Utility entered into a 25-year PPA with AP North Lake, LLC (AP North) for 20 MW of solar photovoltaic energy generated by a new facility located in the City of Hemet, California. The AP North Lake Project became fully operational in August 2015. The project is expected to generate 55,000 MWh of renewable energy per year at a levelized cost of $95 per MWh for the term of the PPA. After a series of ownership changes, AP North Lake is now owned 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 of renewable 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 solar photovoltaic energy generated by two facilities to be built in the City of Lancaster by Silverado Power, which later changed its name to sPower after a series of ownership changes. The two projects are referred to as Antelope Big Sky Ranch and Summer Solar, each rated at 20 MW. The Electric Utility has a 50 percent share of the output from each project through SCPPA, which has two 20 MW PPAs with sPower. Summer Solar became commercially operational on July 25, 2016, and Antelope Big Sky Ranch became commercially operational on August 19, 2016. The Electric Utility’s share from the two projects is 55,000 MWh of renewable energy per year. The price under the agreements is $71.25 per MWh over the term of the agreements. In 2021, sPower merged with the AES Corporation, resulting in AES becoming the new parent company.

On September 19, 2013, the Electric Utility entered into a 20-year PSA with SCPPA for 14 MW of solar photovoltaic energy generated by a facility to be built by First Solar in Kern County, California. The project is referred to as the Kingbird B Solar Photovoltaic Project, with a nameplate capacity of 20 MW. The Electric Utility has a 70 percent share of the output from the project through SCPPA, which has a 20 MW PPA with Kingbird Solar B, LLC, which was acquired by Capital Dynamics in 2018. The project became commercially operational on April 30, 2016. The Electric Utility’s share from the project is approximately 35,000 MWh of renewable energy per year with an all-in price for energy, capacity and environmental attributes of $68.75 per MWh over the term of the agreement.

On September 19, 2013, the Electric Utility entered into a 20-year PSA with SCPPA for 11.1 MW of solar photovoltaic energy generated by a facility to be built by Recurrent Energy in Kern County, California. The project, referred to as Columbia Two Solar Photovoltaic Project, has a nameplate capacity of 15 MW. On March 14, 2014, a Consent and Agreement was entered into by SCPPA consenting to the transfer of ownership of the Columbia Two project from Recurrent Energy to Dominion Resources. The Columbia Two Project completed construction and achieved commercial operation in December 2014. The Electric Utility has a 74.3 percent share (11.1 MW) of the output from the Columbia Two Project through SCPPA, which has a 15 MW PPA with Dominion Resources. The Electric Utility’s share of Columbia Two is approximately 33,000 MWh of renewable energy per year with an all-in price for energy, capacity and environmental attributes of $69.98 per MWh over the term of the agreement. In 2021, Onward Energy, LLC became the new parent company of Columbia Two.

On December 6, 2013, the Electric Utility and FPL Energy Cabazon Wind, LLC (Cabazon Wind) entered into a 10-year PPA for 39 MW of renewable wind energy from the Cabazon Wind Energy Center near Cabazon, California. Cabazon Wind is an existing renewable resource that has been in commercial operation since 1999. SCE purchased the output of the facility through December 2014. At the expiration of SCE’s contract, Cabazon Wind entered into new interconnection and generation agreements with CAISO and SCE. The developer completed the implementation of the transition to the Electric Utility as of January 1, 2015. Delivery under the PPA commenced on January 1, 2015. The project is expected to generate 71,200 MWh of renewable energy per year with an all-in price for energy, capacity and environmental attributes of $59.30 per MWh over the term of the agreement. In 2018, after it was acquired by GlidePath Power Solutions, FPL Energy Cabazon Wind, LLC changed its name to GPS Cabazon Wind, LLC. 69NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC69
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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 7.3 MW of solar photovoltaic energy generated by a facility to be built on the City-owned Tequesquite Landfill. The project was fully commissioned and operational on September 30, 2015 and is expected to generate approximately 15,000 MWh of renewable 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 after acquiring 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 energy generated by sPower’s Antelope DSR Solar PV Project in the City of Lancaster, California. The Electric Utility has a 50 percent share of the output from the project through SCPPA, which has a 50 MW PPA with sPower. The project became commercially operational on December 20, 2016. The Electric Utility’s share of Antelope DSR Solar is expected to generate approximately 71,000 MWh of renewable energy per year with an all-in price for energy, capacity and environmental attributes of $53.75 per MWh over the term of the agreement. In 2021, sPower merged with the AES Corporation, resulting in AES becoming the new parent company.

On November 16, 2017, the Electric Utility entered into a 5-year PSA with SCPPA for 0.8 MW of biomass energy generated by American Renewable Power (ARP) - Loyalton Biomass Project. The Electric Utility has a 4.48 percent share of 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 project began delivery on April 20, 2018. The Electric Utility’s share of ARP Loyalton is expected to generate 6,358 MWh of renewable energy per year with an all-in price for energy, capacity and environmental attributes of $97.50 per MWh over the 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 ARP Loyalton project to Sierra Valley Enterprise.

On January 15, 2021, the Electric Utility entered into a 20-year PSA with SCPPA for 10 MW for the first 5 years of the contract and 30 MW for the remaining 15 years of the contract of geothermal energy generated by Atlantica's Coso Geothermal project. The Electric Utility has partnered with the cities of Banning and Pasadena to share SCPPA's contracted capacity. The project began delivery on January 1, 2022. The Electric Utility's share of Coso Geothermal is expected to provide 87,500 MWh annually in the first 5 years of the term and 268,300 MWh in the remainder of the term at an all-in price for energy, capacity, Resource Adequacy, and environmental attributes of $69.00 per MWh over the term of the agreement.

On February 16, 2021, the Electric Utility entered into a 5-year SB 859 Purchase Agreement with Roseburg Forest Products Co for the remaining 0.5 MW of SB 859 compliance. The Electric Utility has a 4.48 percent share of the output of the project along with SCPPA, Modesto Irrigation District, Sacramento Municipal Utility District, and Turlock Irrigation District, for a total capacity of 11 MW with Roseburg. The project began delivery on February 16, 2021. The price for the SB 859 compliant capacity is $46.00 per MWh over the term of the agreement.

CAP-AND-TRADE PROGRAM
Assembly Bill (AB) 32, enacted in 2006, mandated that the California Air Resources Board (CARB) develop regulations for the reduction of greenhouse gas (GHG) emissions to the 1990 levels by the year 2020. Subsequently, Senate Bill (SB 32), enacted in 2016, 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 to continue the Cap-and-Trade Program and regulations until 2030. In January 2013, emission compliance obligations developed by CARB began under the Cap-and-Trade Program (Program). This Program requires electric utilities to have GHG allowances on an annual basis to offset GHG emissions associated with generating electricity. To ease the transition and mitigate the rate impacts to retail customers, CARB will allocate certain amounts of GHG allowances at no cost to electrical distribution utilities. The Electric Utility’s free allocation of GHG allowances is expected to be sufficient to meet 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 the CARB quarterly auctions. In fiscal years ended June 30, 2023 and 2022, the Electric Utility received $18,317 and $14,960, 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 restricted 70NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. COMMITMENTS (CONTINUED)

CAP-AND-TRADE PROGRAM (CONTINUED)
Regulatory Requirement reserve to comply with regulatory restrictions and governing requirements related to the use of the GHG proceeds. The available funds are to be utilized for qualifying projects, consistent with the goals of AB 32 to benefit the retail ratepayers. The balance in the Regulatory Requirement reserve was $21,707 and $16,366 as of June 30, 2023 and 2022, 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 $485 as of June 30, 2023 and 2022, and is recorded as inventory on the Statements of Net Position.

LOW CARBON FUEL STANDARD PROGRAM
Assembly Bill (AB) 32, enacted in 2006, mandated that the California Air Resources Board (CARB) develop regulations for the reduction of greenhouse gas (GHG) emissions to the 1990 levels by the year 2020. Subsequently, Senate Bill (SB 32), enacted in 2016, 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. Similar to the Cap-and-Trade Program, the Low Carbon Fuel Standard (LCFS) Program is a key component of the market mechanisms authorized by these bills to achieve the State’s GHG emissions reduction goals. The LCFS regulation was initially approved by CARB in 2009. The program then underwent some litigation in the State of California and the regulation was re-adopted in 2015 with modifications and went into effect in 2016. LCFS seeks to reduce the carbon intensity (CI) of fuels used for transportation by establishing an annual CI target.

Fuels that have a CI greater than the target have a compliance obligation and are required to turn in LCFS credits; fuels with a CI lower 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 that generates LCFS credits and participation in the Program is voluntary. The City opted into the LCFS program in March 2018 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 electric forklifts charging at private businesses (forklift credits). CARB calculates the credits that the Electric Utility receives and the 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 Program participate in and manage a statewide point-of-sale rebate program for new electric vehicles. This program is called the California Clean Fuel Reward Program (CFR) and the City joined the program in May 2020. To fund the program, electric utilities are required to contribute proceeds received from the sales of residential base credits beginning with the credits the Electric Utility received in Q4 2019 (generated from electricity used for transportation in Q2 2019). Residential base credits 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 in November 2020, deposits to the CFR program are required by March 31 annually.

In fiscal years ended June 30, 2023 and 2022, the Electric Utility’s proceeds from the sale of LCFS credits was $683 and $1,047, respectively. These proceeds are included on the Statements of Revenues, Expenses and Changes in Net Position as other operating revenue. The Electric Utility has established a restricted Regulatory Requirement reserve to comply with regulatory restrictions and governing requirements related to the use of the LCFS proceeds. The available funds are to be utilized for qualifying programs that support the Electric Utility’s customers who are existing and future electric vehicle owners. Total expenses for qualifying programs as of June 30, 2023 and 2022 was $194 and $210, respectively. The balance in the Regulatory Requirement reserve as of June 30, 2023 and 2022 was $3,795 and $3,233, respectively.

CONSTRUCTION COMMITMENTS
As of June 30, 2023 , the Electric Utility had commitments (encumbrances) of approximately $25,674 with respect to ongoing capital projects, of which $16,623 is expected to be funded by bonds, $7,676 to be funded by unrestricted cash reserves, and $1,375 to be funded by restricted cash reserves.

FORWARD PURCHASE/SALE AGREEMENTS
In order to meet seasonal energy needs and summer peaking requirements, the Electric Utility contracts on a monthly and/or quarterly basis for the purchase or sale of natural gas, electricity and/or capacity products on a one to four year 71 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC71
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. COMMITMENTS (CONTINUED)

FORWARD PURCHASE/SALE AGREEMENTS (CONTINUED)
forward time horizon. As of June 30, 2023 , the Electric Utility has net natural gas and electricity commitments for fiscal year 2024 and thereafter of approximately $112,355, with a market value of $112,807.

12. LITIGATION
The Electric Utility is a defendant in various lawsuits arising in the normal course of business. Present lawsuits and other claims against the Electric Utility are incidental to the ordinary course of operations of the Electric Utility and are largely covered by the City’s self-insurance program. In the opinion of management and the City Attorney, such claims and litigation 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 against the City seeking to invalidate, rescind and void, under Proposition 26, the Electric System’s rates approved by City Council on May 22, 2018, which took effect on January 1, 2019, by challenging the portion of the electric rates that are attributable to the General Fund. The petition did not seek any monetary relief from the General Fund. The trial court divided the case into two stages for hearings: a liability phase and a damages phase. On April 17, 2020, the Court in the liability phase of Parada II litigation entered a tentative ruling finding the City’s electric rates attributable to the General Fund transfer violate Article XIII C of the California Constitution. The formal hearing on the matter took place on June 5, 2020, but the Court asked for further briefing on the issue of whether or not the plaintiffs failed to exhaust their administrative remedies. On October 9, 2020, the Court confirmed its tentative ruling and entered an order denying the City’s request for interlocutory remand. The court had set a hearing for February 24, 2021, to set a briefing schedule for determining appropriate remedies/damages in the case. The City expected the second phase of the trial relating to plaintiffs’ available remedies to occur 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 Fund revenues) from the Electric Fund. Based on the Court’s order in the liability phase of the trial, approximately $19-32 million of 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 to refund rate payers for the portions of the rates that were determined to violate Article XIII C of the California Constitution from the date the writ of mandate was filed. However, the trial court did not issue any ruling as to what the amount of any damages 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 by the trial court after anticipated appeals are resolved. This amount could vary depending upon whether or not the City decides 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 was conditioned on: (1) the Riverside City Council’s placement of a ballot measure on City ballots in November 2021 to approve the City’s General Fund Transfer practices as a general tax (“Ballot Measure”); and (2) voter approval of the Ballot Measure. The Riverside City Council placed the Ballot Measure on the ballot for the November 2, 2021 election. The Parties stayed the Parada lawsuit until certification of the results of the Ballot Measure. If voters approved the Ballot Measure, the City would refund to customers of its electric utility an amount equal to $24 million less the amount awarded to Plaintiffs’ counsel in fees, paid over a five year period beginning no later than February 1, 2022.

If voters did not approve the Ballot Measure, this litigation would then resume.

On or about September 16, 2021, a petition for writ of mandate entitled Riversiders Against Increased Taxes v. City of Riverside, et al. (“RAIT lawsuit”) was filed against the City challenging the Ballot Measure on the grounds that the Ballot Measure cannot be adopted at the November 2021 election because that election is a “special” election and under Proposition 218, a ballot measure to impose a general tax can only be submitted to voters at a general election. On November 9, 2021, the court set a trial date for the RAIT lawsuit for January 7, 2022 and ordered a stay of the certification of the Ballot Measure Election results pending the January 7th hearing but did not otherwise delay or cancel the election for 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. 72NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

12. LITIGATION (CONTINUED)
On April 26, 2022 the RAIT lawsuit trial court determined that the November 2021 election was a “special election” rather than a “general election” and therefore did not comply with Proposition 218. The RAIT lawsuit trial court further ruled that it lacked power to enjoin the certification of election results or to otherwise invalidate the election. Both sides have since appealed that ruling. The appeals have been fully briefed as of June 26, 2023. No date for oral argument has been set.

On May 12, 2022, the City and the Paradas amended the May 17, 2021 Settlement Agreement, with the following additional terms: (a) City agreed to start making refunds to ratepayers by October 1, 2022; (b) if the City prevailed in the appeal of the trial court’s decision in the RAIT lawsuit, no additional refund would be due to the ratepayers; (c) if the City did not prevail in the appeal of the trial court’s decision in the RAIT lawsuit, an additional refund would be implemented in the amount of $705,882 per month, from November, 2021 up to when the City either (i) sets new electric rates; (ii) voters approve a valid ballot measure for the GFT or (iii) the City otherwise stops collecting the electric GFT. The Parada lawsuit was 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 from the RAIT lawsuit sought to intervene in the Parada lawsuit and set aside this dismissal. On August 3, 2022, the Parada trial court refused to set aside the dismissal. The City has now begun to implement the settlement agreement.

13. EXTRAORDINARY ITEM
In fiscal year 2021/22, SCE provided the 2020 Decommissioning Cost Estimate report, which projected a material increase in costs for the Electric Utility over the life of the SONGS decommissioning project. As a result, it was determined that the decommissioning liability be increased. The increase in the decommissioning liability of $5,748 was reported as an extraordinary item on the Statements of Revenue, Expenses and Changes in Net Position as of June 30, 2022. For additional information related to SONGS, refer to Note 10.

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS For the year ended June 30, 2022, the financial statements included the adoption of GASB Statement No. 87, Leases. The primary objective of this statement is to enhance the relevance and consistency of information about governments' leasing activities. This statement establishes a single model for lease accounting based on the principle that leases are financings of the right to use an underlying asset. Under this statement, a lessee is required to recognize a lease liability and a lease asset, and a lessor is required to recognize a lease receivable and a deferred inflow of resources. For additional information, refer to the disclosures below.

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 a SBITA as a contract that conveys control of the right to use another party's information technology software, alone or in a combination with tangible capital assets, as specified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer to the disclosures below.

LEASES PAYABLE
The Electric Utility has 23 leases as Lessee for the use of various pieces of machinery and equipment as of the end of the fiscal year. The Electric Utility is required to make principal and interest payments through fiscal year 2026. An initial lease liability was recorded in the amount of $625. As of June 30, 2023, the value of the lease liability is $362. The leases have an interest rate of 0.52%. The value of the lease assets as of June 30, 2023 is $628 with accumulated amortization of $273 and is shown on the Asset Class activities table found below. 73 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC73
ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

LEASES PAYABLE (CONTINUED)
Amount of Lease Assets by
Major Classes of Underlying
Asset
Asset Class
Lease Asset
Value
Accumulated
Amortization
Building $ 348 $ (149)
Machinery and
Equipment 280 (124)
Total $ 628 $ (273)
Fiscal Year
Principal
Payments
Interest
Payments
Total
Payments
2024 $ 137 $ 2 $ 139
2025 136 1 137
2026 89 - 89
Total $ 362 $ 3 $ 365

LEASES RECEIVABLE
The Electric Utility has 11 leases as a Lessor for the use of various pieces of building and equipment as of the end of the fiscal year. The terms range from 6 to 30 years beginning on the contract commencement date. An initial lease receivable was recorded in the amount of $1,328. As of June 30, 2023, the value of the lease receivable is $11,766. The leases have interest rates ranging from 0.52% to 1.68%. The value of the deferred inflow of resources as of June 30, 2023 was $11,394, and the Electric Utility recognized lease revenue of $1,583 during the fiscal year.

Fiscal Year
Principal
Payments
Interest
Payments
Total
Payments
2024 $ 1,359 $ 131 $ 1,490
2025 1,412 118 1,530
2026 1,365 106 1,471
2027 1,436 94 1,530
2028 1,165 83 1,248
2029-2033 2,416 306 2,722
2034-2038 1,819 138 1,957
2039-2043 794 15 809
Total $ 11,766 $ 991 $ 12,757
74 ELECTRIC UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

14. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS PAYABLE The Electric Utility has 2 subscription-based information technology arrangement (SBITA) for the use of various software as of the end of the fiscal year. The Electric Utility is required to make principal and interest payments through fiscal year 2025. An initial lease liability was recorded in the amount of $32. As of June 30, 2023, the value of the subscription liability was $49. The subscriptions have an interest rate of 0.52%. The value of the subscription asset as of June 30, 2023 is $93 with accumulated amortization of $43.

Fiscal Year Principal Interest Total Payments
2024 $ 42 $ - $ 42
2025 7 - 7
Total $ 49 $ - $ 49
75 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC75
ELECTRIC UTILITY:

KEY HISTORICAL OPERATING DATA
Fiscal Year 2022/23 2021/22 2020/21 2019/20 2018/19

POWER SUPPLY MEGAWATT-HOURS (MWH)
Nuclear
Palo Verde 101,500 101,100 99,800 100,900 100,200
Coal
Intermountain Power 460,400 453,900 539,200 551,300 677,900 Hoover (Hydro) 22,900 28,000 30,600 27,000 28,600
Gas
Springs 1,400 600 1,800 700 400
RERC 76,000 54,400 83,800 68,200 93,900
Clearwater 15,200 13,000 9,800 8,600 13,700
Renewable resources 1,010,800 1,272,700 1,029,300 922,800 835,500 Market purchases 551,700 359,200 468,000 558,500 511,500 Total 2,239,900 2,282,900 2,262,300 2,238,000 2,261,700 System peak megawatt (MW) 647.8 575.9 630.3 587.2 610.9

ELECTRIC USE
Number of meters as of year end
Residential 100,054 99,731 99,226 98,930 98,322
Commercial3 12,026 11,922 11,817 11,598 11,537
Industrial3 622 625 616 581 570
Other 49 50 52 52 51
Total 112,751 112,328 111,711 111,161 110,480
Millions of kilowatt-hours (kWh) sales
Residential 786 759 783 723 722
Commercial3 440 443 430 442 460
Industrial3 920 923 891 931 947
Other 15 19 18 18 21
Subtotal 2,161 2,144 2,122 2,114 2,150
Wholesale2 14 2 - 1 -
Total 2,175 2,146 2,122 2,115 2,150

ELECTRIC FACTS
Average annual kWh
per residential customer 7,873 7,632 7,907 7,322 7,375
Average price (cents/kWh)
per residential customer $ 17.88 $ 17.71 $ 17.03 $ 16.77 $ 16.11 Debt service coverage ratio (DSC)4,5,6,7 2.01 2.03 1.99 2.62 2.24 Operating income as a percent
of operating revenues %10.0 %18.6 %9.6 %12.1 %11.4
Employees1 473 473 468 466 475
1 Approved positions.
2 For fiscal years 18/19 and 20/21, wholesale kWh was less than 1 million kWh. Increase in fiscal year 22/23 was due to a transmission constraint requiring the power the Electric Utility was scheduled to receive to be resold. 3 Changes in fiscal years 18/19, 19/20 and 20/21 reflect reclassification of certain Industrial and Commercial accounts related to contract accounts. 4 Interest expense used to calculate DSC is net of federal subsidy on Build America Bonds. 5 Does not include GASB 68 - Accounting and Financial Reporting for Pension non-cash adjustments of ($1,308), ($16,425), $9,682, $3,364, and ($1,323) for fiscal years 22/23 through 18/19, respectively.
6 Does not include GASB 75 - Accounting and Financial Reporting for Post-employment Benefits Other than Pensions non-cash adjustments of $431, $530, $183, $490, and $300 for fiscal years 22/23 through 18/19, respectively. 7 Includes GASB 87 Leases net revenue adjustment of $247 and $134 for fiscal years 22/23 and 21/22, respectively. 76 KEY HISTORICAL OPERATING DATA: ELECTRIC

SOURCE OF

REVENUE
Residential Sales 32¢
Industrial Sales 27¢
Commercial Sales 17¢
Transmission Revenue 8¢
Other Revenue 8¢
Use of Reserves 4¢
Public Benefit Programs 2¢
Other Sales 1¢
Investment Income 1¢

DISTRIBUTION OF

REVENUE
Production 43¢
Distribution 16¢
Transmission 15¢
Debt Service 10¢
Transfers to the City's General Fund* 9¢
Additions & Replacements to the System 6¢
Public Benefit Programs 1¢
ENERGY
RESOURCES**
Renewables 45%
Market Purchases 25%
Coal 19%
Nuclear 5%
Gas 5%
Hydropower 1%
San Diego Gas & Electric
Southern California
Edison
Riverside Public
Utilities
$0
$50
$100
$150
$200
$250
$300
179% Higher 88% Higher $107
*Based on transfer of 11.5% of fiscal year
2021/2022 gross operating revenues including
adjustments.
**Energy Resources are based on calendar year 2022
as filed with the California Energy Commission

$298 $201
77 KEY HISTORICAL OPERATING DATA: ELECTRIC
77 $39.9
$39.6
$39.9
$39.4
$42.3
2019
2020
2021
2022
2023
General Fund Transfer (In Millions)
1 110,480
111,161
111,711
112,328
112,751
2019
2020
2021
2022
2023
Number of Meters At Year End
$362.7
$367.1
$372.1
$398.6
$418.9
2019
2020
2021
2022
2023
Total Operating Revenue (In Millions)
2,262
2,238
2,262
2,283
2,240
2019
2020
2021
2022
2023
Production (In Million Kilowatt-Hours)
610.9
587.2
630.3
575.9
647.8
2019
2020
2021
2022
2023
Peak Day Demand (In Megawatts)
78 KEY HISTORICAL OPERATING DATA: ELECTRIC

ELECTRIC FACTS AND SYSTEM DATA
Established................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................1895 Service Area Population................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................313,676 City Service Area Size (square miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................81.5 System Data
Transmission Lines (circuit miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................99.2 Distribution Lines (circuit miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................1,355 Number of Substations................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................16 2022-23 Peak Day (megawatts)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................648 Highest Single Hourly Use:
09/07/2022, 4pm, 99.3 degrees
Historical Peak (megawatts)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................648 Highest Single Hourly Use:
09/07/2022, 4pm, 99.3 degrees
Bond Ratings
Fitch Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA- S & P Global Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA- 79 KEY HISTORICAL OPERATING DATA: ELECTRIC79

WATER
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WATER UTILITY:

MANAGEMENT'S DISCUSSION AND ANALYSIS
As management of Riverside Public Utilities, a department of the City of Riverside (the City), we offer the readers this narrative overview and analysis of the 2022-23 financial report for the periods ended June 30, 2023 and 2022 for Riverside’s Water Utility (Water Utility), an enterprise fund of the City. We encourage readers to consider the information presented here in conjunction with additional information furnished in our financial statements, which begin on page 98 of this report. All amounts, unless otherwise indicated, are expressed in thousands of dollars.

FINANCIAL HIGHLIGHTS
 Governmental Accounting Standards Board No. 96, Subscription-Based Information Technology Agreements (GASB 96) - 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 that conveys control of the right to use another party’s information technology software, alone or in a combination with tangible capital asset, as specified in a contract for a period of time in an exchange or exchange-like transaction. For additional 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 $69,854 and $72,452 for the fiscal years ended June 30, 2023 and 2022, respectively. The decrease in sales was primarily due to a decrease in consumption, offset by the rate plan increase.
 Total revenue includes the accounting standard for fair market value adjustment of investments, which will continue to fluctuate based on market valuations. The adjustment was $(536) and $(1,922) in June 30, 2023 and 2022, respectively.
 Operating expense reflects a non-cash pension accounting standard adjustment, which will continue to fluctuate based on yearly actuarial information provided by the California Public Employees' Retirement System (CalPERS). The adjustment was $(471) and $(4,891) in June 30, 2023 and 2022, respectively.

OVERVIEW OF THE FINANCIAL STATEMENTS
This discussion and analysis is intended to serve as an introduction to the Water Utility’s financial statements. The Water Utility is a department of the City, and its activities are recorded in a separate enterprise fund. These financial statements include only the activities for the Water Utility and provide comparative information for the last two fiscal years. Information on 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 the financial statements. In addition, this report also contains other supplementary information to provide the reader with additional information about the Water 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 the Water Utility’s financial health.

The Statements of Net Position present information on all of the Water Utility’s assets, liabilities, deferred inflows and outflows of resources and net position. The Statements of Net Position provide information about the nature and amount of the Water Utility’s resources and obligations at a specific point in time.

The Statements of Revenues, Expenses and Changes in Net Position report all of the Water Utility’s revenues and expenses for the periods shown.

The Notes to the Financial Statements provide additional information that is essential to a full understanding of the data provided in the Water Utility's financial statements. The Notes to the Financial Statements begin on page 103 of this report.
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CONDENSED STATEMENTS OF NET POSITION
2023 2022 2021
Current and other assets $ 218,580 $ 174,574 $ 92,883
Capital assets 513,341 508,310 499,636
Deferred outflows of resources 16,990 9,647 14,528
Total assets and deferred outflows of resources 748,911 692,531 607,047 Long-term debt outstanding 290,760 239,544 250,728
Other liabilities 44,364 32,469 47,195
Deferred inflows of resources 86,374 98,214 764
Total liabilities and deferred inflows of resources 421,498 370,227 298,687 Net investment in capital assets 295,560 293,641 291,541 Restricted 12,478 10,988 10,599
Unrestricted 19,375 17,675 6,220
Total net position $ 327,413 $ 322,304 $ 308,360

ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
2023 compared to 2022 The Water Utility’s total assets and deferred outflows of resources were $748,911, reflecting an increase of $56,380 (8.1%) primarily due to the following:
 Current and other assets, comprised of restricted and unrestricted assets, had a net increase of $44,006, primarily due to an increase of $52,198 in restricted cash and cash equivalents related to the issuance of the 2022 Water Revenue Bonds Series A. The increase is offset by a decrease of $8,809 in net pension asset as a result of pension accounting standards.
 Capital assets increased by $5,031 as a result of an increase in additions and improvements to the Water distribution infrastructure system to improve service and reliability to Water Utility's customers, offset by an increase in current years 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 outflows related to pension as a result of pension accounting standards. The increase is offset by a decrease of $812 in the fair market value of derivatives and a decrease of $270 in loss on refunding due to the amortization. 2022 compared to 2021 Total assets and deferred outflows of resources were $692,531, reflecting an increase of $85,484 (14.1%) over prior year.
 Current and other assets, comprised of restricted and unrestricted assets, had a net increase of $81,691, primarily due to an increase of $82,983 in lease receivable related to the implementation of GASB 87, an increase of $8,809 in net pension asset as a result of pension accounting standards, and an increase of $6,129 in unrestricted cash and cash equivalents, primarily due to positive operating result, offset by a decrease of $15,442 in restricted cash and cash equivalents due to the use of bond proceeds for capital projects.  Capital assets increased by $8,674 as a result of an increase in additions and improvements to the Water distribution infrastructure system to improve service and reliability to Water Utility's customers, offset by an increase in current years depreciation.
 Deferred outflows of resources decreased by $4,881, primarily due to a decrease of $2,630 in the fair market value of derivatives, a decrease of $1,841 in deferred outflows related to pension as a result of pension accounting standards, and a decrease of $266 in loss on refunding due to the amortization. 85 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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LIABILITIES AND DEFERRED INFLOWS OF RESOURCES
2023 compared to 2022 The Water Utility’s total liabilities and deferred inflows of resources were $421,498, an increase of $51,271 (13.8%) primarily due to the following:
 Long-term debt outstanding increased by $51,216, primarily due to the issuance of the 2022 Water Revenue Bonds Series A. Additional debt information can be found in the “Capital Assets and Debt Administration” section.  Other liabilities increased by $11,895, primarily due to an increase of $12,854 in net pension liability, an increase of $1,281 in the current portion of long-term obligations, and an increase of $600 in accrued interest payable. The increase is offset by a decrease of $1,269 in derivative instruments due to a decrease in the fair market value of interest rate swaps, and a decrease of $1,093 in unearned revenues. Additional information on note payable can be found in Note 4 of the accompanying financial statements.  Deferred inflows of resources decreased by $11,840 , primarily due to a decrease of $13,627 in pension-related adjustments, which included the changes in assumptions, the differences between expected and actual experience and the change in projected versus actual earnings on pension plan investments as determined by the plan actuary.

The decrease is offset by an increase of $1,264 related to GASB 87 lease adjustments. 2022 compared to 2021 Total liabilities and deferred inflows of resources were $370,227, reflecting an increase of $71,540 (24.0%).
 Long-term debt outstanding decreased by $11,184, primarily due to principal payments on revenue bonds, pension obligation bonds, note payable and financed purchases.
 Other liabilities decreased by $14,726, primarily due to a decrease of $12,203 in net pension liability due to the elimination of the CalPERS net pension liability to net pension asset, a decrease of $3,037 in derivative instruments due to a decrease in the fair market value of interest rate swaps, and a decrease of $1,202 in unearned revenues with the City of Corona, offset by an increase of $601 in accrued interest payable, an increase of $568 in the current portion of long-term obligations, and an increase in accounts payable and other accruals of $446.  Deferred inflows of resources increased by $97,450, primarily due to the implementation of GASB 87, and pension related adjustments, which included the changes in assumptions, the differences between expected and actual experience and the change in projected versus actual earnings on pension plan investments as determined by the plan actuary.

NET POSITION
2023 compared to 2022 The Water Utility’s total net position, which represents the difference between the Water Utility’s total assets and deferred outflows of resources less total liabilities and deferred inflows of resources, totaled $327,413, an increase of $5,109 (1.6%).
 The largest portion of the Water Utility’s total net position, which is its investment in capital assets of $295,560 (90.3%), had an increase of $1,919 from prior year. Investment in capital assets reflects the Water Utility’s investment in source of supply, pumping, treatment, and transmission and distribution facilities, less any related outstanding debt used 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 representing resources that are subject to external restrictions on how they may be used. The increase was primarily due to an increase 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 Conservation Programs, and other legally restricted assets.
 The unrestricted portion of net position totaled $19,375 ( 5.9%) an increase of $1,700 from prior year, primarily attributable to positive operating results and an increase in investment income. Unrestricted net position may be used to meet the Water Utility’s ongoing operational needs and obligations to customers and creditors. 86 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER89
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2022 compared to 2021 Total net position increased by $13,944 (4.5%), to $322,304.  The largest portion of the Water Utility’s total net position, which is its investment in capital assets of $293,641 (91.1%), had an increase of $2,100 from prior year. Investment in capital assets reflects the Water Utility’s investment in treatment, pumping, source of supply, transmission and distribution facilities, less any related outstanding debt used to acquire these assets.
 The restricted portion of net position totaled $10,988 (3.4%), reflecting an increase of $389 and representing resources that are subject to external restrictions on how they may be used. The increase was primarily due to an increase in restricted debt service reserve. Restricted net position is reserved for items such as debt repayment and funds collected for Water Conservation Programs, and other legally restricted assets.  The unrestricted portion of net position totaled $17,675 (5.5%), reflecting an increase of $11,455 from prior year, primarily attributable to positive operating results. Unrestricted net position may be used to meet the Water Utility’s ongoing operational needs and obligations to customers and creditors.

CONDENSED STATEMENTS OF CHANGES IN NET POSITION
2023 2022 2021
Revenues:

Retail sales, net $ 69,854 $ 72,452 $ 70,847
Other revenues 12,109 12,336 12,532
Investment (loss) income 3,613 61 (1)
Capital contributions 4,149 5,693 3,062
Total revenues 89,725 90,542 86,440
Expenses:

Operations and maintenance 42,738 36,366 39,143
Purchased energy 6,632 6,863 6,523
Depreciation 16,367 16,179 16,346
Amortization 20 11 -
Interest expense and fiscal charges 10,689 9,471 9,731
Total expenses 76,446 68,890 71,743
Transfers:

Transfers to the City's general fund (8,170) (7,708) (6,972) Total Transfers (8,170) (7,708) (6,972)
Changes in net position 5,109 13,944 7,725
Net position, July 1 322,304 308,360 300,635
Net position, June 30 $ 327,413 $ 322,304 $ 308,360
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REVENUES BY SOURCES
2023 compared to 2022 The Water Utility’s total revenues of $89,725 decreased by $817 (0.9%) primarily due to the following changes:
 Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $69,854, a decrease of $(2,598) (3.6%) from prior fiscal year. Retail sales continue to be the primary revenue source for the Water Utility. The decrease was due to a 13.7% decrease in consumption.  Other revenues of $12,109 decreased by $227 (1.8%), primarily due to a decrease of of $1,258 related to settlement revenues, offset by an increase of $939 in wholesale water sales compared to prior year.  Capital contribution of $4,149 decreased by $1,544 (27.1%), primarily due to a decrease of $1,202 in contribution in aid.
 Investment income of $3,613 increased by $3,552 (5,823%), primarily due to a fair market value adjustment of investments and a higher overall interest rate in the current fiscal year. 2022 compared to 2021 The Water Utility’s total revenues of $90,542 increased by $4,102 (4.7%) primarily due to the following changes:
 Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $72,452, an increase of $1,605 (2.3%) from prior fiscal year. Retail sales continue to be the primary revenue source for the Water Utility. The increase was due to the rate plan increase offset by a 2.1% decrease in consumption.  Other revenues of $12,336 decreased by $196 (1.6%), primarily due to a decrease of $2,235 in wholesale water sales, offset by an increase of $1,586 related to the SCE Utility billing indifference settlement related to renewable energy self-generation bill and an increase of $608 in water conveyance revenue.  Capital contribution of $5,693 increased by $2,631 (85.9%), mainly due to the donated assets related to transmission mains, fire hydrants and services.
 Investment income of $61 increased by $62 (100%) due to the leases interest income related to the implementation of GASB 87.
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EXPENSES BY SOURCES
2023 compared to 2022 The Water Utility’s total expenses, excluding general fund transfer, were $76,446, an increase of $7,556 (11.0%). 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 in personnel-related costs resulting from the elimination of the prior year net pension asset and generation of a net pension liability in fiscal year 2022-23, along with increases in administration and general operating expenses.  Purchased energy and water expenses of $6,632 decreased by $231 (3.4%) from prior year, primarily due to a decrease of $179 in the electricity and chemical costs. 2022 compared to 2021 The Water Utility’s total expenses, excluding general fund transfer, were $68,890, a decrease of $2,853 (4.0%). The decrease was primarily due to the following:
 Operations and maintenance expenses of $36,366 decreased by $2,777 (7.1%), mainly due to a non-cash pension adjustment as a result of pension accounting standards.  Purchased energy and water expenses of $6,863 increased by $340 (5.2%) from prior year, primarily attributable to an increase in the electric and chemical costs.

TRANSFERS
Pursuant to the City's Charter and the voter approval of Measure A on June 4, 2013, the Water Utility may transfer up to

11.5 percent of prior year’s gross operating revenues, including adjustments, to the City’s general fund. The City uses these funds to help provide needed public services to the residents of the City, including police, fire, parks, libraries and other benefits. The Water Utility transferred $8,170 and $7,708 for 2023 and 2022, respectively, based on the gross operating revenue provisions in the City’s Charter. For additional information, refer to Note 10. 89 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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CAPITAL ASSETS AND DEBT ADMINISTRATION

CAPITAL ASSETS
The Water Utility’s investment in capital assets includes investments in source of supply, pumping, treatment, transmission and distribution facilities, land, intangibles, construction in progress, and lease and subscription assets as well as general items such as office equipment, furniture, etc.

The following table summarizes the Water Utility’s capital assets, net of accumulated depreciation, as of June 30:
2023 2022 2021
Utility plant
Source of supply $ 54,223 $ 55,231 $ 54,424
Pumping 19,304 19,445 20,146
Treatment 25,652 25,868 27,122
Transmission and distribution 335,719 333,483 332,467
General 4,636 4,514 3,032
Land 20,841 20,841 20,841
Intangibles 10,883 11,005 11,469
Construction in progress 42,055 37,907 30,135
Total utility plant 513,313 508,294 499,636
Lease and subscription assets
Machinery and equipment 11 16 -
Subscription-based information technology arrangements 17 - - Total capital assets $ 513,341 $ 508,310 $ 499,636
2023 compared to 2022 The Water Utility’s investment in capital assets, net of accumulated depreciation, was $513,341, an increase of $5,031 ( 0.99%) from prior year. The increase resulted primarily from an increase in construction in progress. The Water Utility's significant capital projects include the following:
 $7,919 in distribution pipelines, such as main replacements, distribution system facilities replacement and system expansion.
 $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. 2022 compared to 2021 The Water Utility's investment in capital assets, net of accumulated depreciation, was $508,310, an increase of $8,674 ( 1.74%) from prior year. The increase resulted primarily from the increase in construction in progress. Significant capital projects included the following:
 $10,414 in distribution pipelines, such as main replacements, distribution system facilities replacement and system expansion.
 $5,343 in transmission pipelines, such as transmission mains.  $2,722 in distribution facilities, such as pump station replacements and meters.  $2,190 in well projects, such as potable irrigation well replacements and facility rehabilitation.

Additional information regarding capital assets can be found in Note 3 of the accompanying financial statements. 90 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER93
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DEBT ADMINISTRATION
The following table summarizes outstanding long-term debt as of June 30:
2023 2022 2021
Revenue bonds $ 243,300 $ 192,190 $ 198,830
Unamortized bond premium 21,994 17,472 18,476
Pension obligation bonds 19,924 21,287 22,363
Contracts payable 933 933 1,067
Financed purchases 985 1,218 1,445
Note payable 15,100 16,639 18,138
Less: Current portion of outstanding debt (11,476) (10,195) (9,591) Total $ 290,760 $ 239,544 $ 250,728
The Water Utility’s bond indentures require a minimum debt service coverage ratio, as defined by the bond covenants, of

1.25. The Water Utility’s debt service coverage ratio was 1.93, 2.23, and 2.25 at June 30, 2023, 2022, and 2021, respectively. The debt is backed by the revenues of the Water Utility. Debt service coverage ratio decreased at June 30, 2022 due to an increase in debt service requirements. For additional information, see Note 4 of the accompanying financial statements and the Key Historical Operating Data section. 2023 compared to 2022 The Water Utility’s long-term debt increased by $51,216 (21.4%) to $290,760 as a result of the issuance of the 2022 Water Revenue Bonds Series A, offset by current year principal payments and amortization of bond premiums.
2022 compared to 2021 The Water Utility’s long-term debt decreased by $11,184 (4.5%) to $239,544 as a result of the principal payments and amortization of bond premiums.

Additional information on the Water Utility’s long-term debt can be found in Note 4 of the accompanying financial statements.

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 water supply, investments in infrastructure and rate competitiveness, among many other factors. 91 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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The State of California has experienced unprecedented drought conditions in recent years resulting in severe impacts to California’s water supplies and its ability to meet all of the demands for water in the State. The Water Utility is very fortunate as a water provider in California in that the Water Utility owns, operates and maintains its own water supply and is not typically dependent on imported water from outside sources. The Water Utility currently has sufficient water supplies to meet customer needs even during severe drought conditions; however, the aquifers the Water Utility draws from are experiencing historic low levels. The Water Utility has responded by continuing to offer a wide variety of water conservation programs 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 water usage and utility costs, and help the City meet State mandates and be more sustainable. These programs provide rebates for residents and businesses to help them save money by conserving water. In an effort to streamline and automate the rebate process, the City formed a partnership with Metropolitan Water District of Southern California to administer and process 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 residences and businesses, the Water Utility, in partnership with the City created the Street Park Turf Conversion and Demonstration Garden at the Janet Goeske Center. The Demonstration Garden allows residents and businesses to interact with water conservation materials and techniques that conserve water, elevate customer awareness, increase incentive program participation, provide educational opportunities and demonstrate water conservation best practices.

The Water Utility’s long-range water supply planning includes significant contributions of both conservation and recycled water. 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 conservation measures could negatively impact the Water Utility revenues and has been addressed in the recent cost of service analysis conducted by the Water Utility.

During fiscal year 2022/23, RPU’s water use efficiency programs have supported residents and business to save in excess of 21.8 million 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 CONSERVATION
On November 10, 2009, the Governor signed SBX7-7, which focused on reducing urban (municipal) water use, mainly through reductions in residential potable water use, throughout California. The Water Utility’s 2015 Urban Water Management Plan (UWMP) reported its Baseline Water Use and calculated its 2020 Urban Water Use Target. In its 2020 UWMP, the Water Utility demonstrated its compliance with SB X7-7 by showing actual 2020 water use below its 2020 Urban Water Use Target.

On May 31, 2018, Governor Jerry Brown signed long-term water-use efficiency bills Senate Bill 606 and Assembly Bill 1668 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-based approach 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's unique efficient water use target. Final regulations are anticipated to be set in 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 in 2022 and a Drought Risk Assessment every 5 years as part of its Urban Water Management Plan. 92 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER95
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WATER STANDARDS
The development of new and increasingly stringent drinking water regulations by the California Environmental Protection Agency (CalEPA) and the U.S. Environmental Protection Agency (USEPA) are significantly impacting water supply costs throughout the state and the nation. New chemical and biological contaminants are being discovered through more sophisticated research techniques and improved analytical methods. In addition, public health and environmental agencies are now evaluating how anthropogenic factors are impacting our water supplies. Pesticides, pharmaceuticals, and personal care products are being evaluated at trace levels, which can be orders of magnitude lower than what was achievable 20 years ago. As a result, water treatment costs are increasing as federal and state legislators and regulators try 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 regulate perchlorate after finding that perchlorate did not occur with a frequency and at levels of public health concern within the meaning of the Safe Drinking Water Act, and that development of a regulation did not present a meaningful opportunity for health risk reduction for persons served by public water systems. However, the State of California began regulating perchlorate in 2007 with a MCL set at 6 parts per billion (“ppb”) and a detection level for purposes of reporting (DLR) of 4 ppb. Beginning July 1, 2021, the DLR was lowered to 2 ppb and will be lowered to 1 ppb effective January 1, 2024. After data is collected at these lower DLR’s evaluation of the perchlorate MCL, and possible need for reduction, will occur. A reduction 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 not need to be revised) and that eight NPDWRs are candidates for regulatory revision. These eight NPDWRs are included in the Stage 1 and the Stage 2 Disinfectants and Disinfection Byproducts Rules, the Surface Water Treatment Rule, the Interim Enhanced Surface Water Treatment Rule and the Long Term 1 Enhanced Surface Water Treatment Rule. The eight 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 Water Utility’s water supply costs. In June 2020, the USEPA began collecting contaminant occurrence data and treatment technique 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 of the City’s potable wells show detections of 1,2,3-TCP that exceed the MCL. These wells extract water from the same aquifers that are contaminated by other known anthropogenic chemicals and are currently being treated by existing GAC treatment facilities.

Perfluorooctanoic acid (PFOA) and perfluorooctane sulfonic acid (PFOS) are fluorinated organic chemicals which are part of a family of compounds referred to as per- and polyfluoroalkyl substances (PFAS). PFAS are synthetic compounds that are water and lipid resistant and are useful for a variety of manufacturing processes and industrial applications. In May 2016, the USEPA issued a lifetime health advisory for PFOA and PFOS in drinking water of a combined level of 70 ppt. In February 2021, the USEPA determined to move forward with the process of implementing a national primary drinking water regulation for PFOA and PFOS. In March 2023, the USEPA issued health-based, non-enforceable Maximum Contaminant 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 proposed MCLs follow:

PFOA at 4 ppt, PFOS at 4 ppt, and PFNA, PFHxS, PFBS and GenX regulated together as a Hazard index where the ratio of the chemicals when added together must be less than 1. The Hazard index established Health Based Water Concentrations for PFHxS of 9ppt, PFNA at 10ppt, GenX at 10ppt, and PFBS at 2,000ppt. The proposed PFAS NPDWR is anticipated to be promulgated at the end of 2023 and become effective by the end of 2026. In addition, the USEPA proposed designating PFOA and PFOS as hazardous substances under CERCLA which would increase transparency and hold polluters accountable however, could also increase disposal costs for spent GAC or IX media used to remove PFAS.

With respect to California, in August 2019, the SWRCB-DDW established Notification Levels for PFOA and PFOS of 5.1 and 6.5 ppt, respectively, and in February 2020, DDW issued updated drinking water response levels of 10 ppt for PFOA and 40 ppt for PFOS based on a running four-quarter average. On February 6, 2020 the SWRCB tasked OEHHA to set advisory 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 a 93MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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notification level of 500 ppt and a response level of 5000 ppt, by the SWRCB. In June 2021, the Office of Environmental Health 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 and a Response Level of 20 ppt in October of 2023.

The City believes that PFAS have been in the groundwater basins from which the City draws water in very low concentrations for many years. Recent technological advances enabled water agencies to detect PFAS compounds at such low concentrations. The City’s goal is to remain below the Notification Levels, which are lower than the Response Level. Many of the City’s wells with detections of PFAS also extract water from the same aquifers that are contaminated by other 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 feasibility of resurrecting an abandoned treatment plant to treat a well field with high levels of PFAS and develop a long-term water treatment strategy. The Board’s review and approval of contracts within the original approved project is ongoing.

The Water Utility will continue to monitor the progress of the proposed standard changes and will advocate for standards that protect human health and are based on the best available science.

CLEAN WATER ACT
In April 2020, the US EPA and US Army published the Navigable Waters Protection Rule to define “Waters of the United Sates.” 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 the regulatory text that have never been defined before. This definition was different from that of the 2015 Clean Water Rule which would have expanded the scope of Federal jurisdiction. However, in June 2021, the USEPA and Department of the Army announced their intent to initiate a new rulemaking process that restores the protections in place prior to the 2015 rule and develops a new rule to establish a durable definition of “Waters of the US” that reflects consideration of prior Supreme Court decisions. This rulemaking process follows a review conducted by the agencies as directed by the January 20, 2021 Executive Order 13990 on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” The public comment period closed in February 2022.

FIVE-YEAR WATER RATE PLAN
On May 22, 2018, the City Council approved a five-year Water Rate Plan, the final annual rate increase of 6.5% was effective July 1, 2022 and was in effect through June 30, 2023.

On September 19, 2023, the City Council approved a new five-year Water Rate Plan, which includes system average annual rate increases. The first annual rate increase is effective October 1, 2023 with the following four years effective on July 1 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 was designed to provide financial stability and correct the imbalance of costs versus revenue recovery.

REQUESTS FOR INFORMATION
This financial report is designed to provide a general overview of the Water Utility’s finances. Questions concerning any information provided in this report or requests for additional financial information should be addressed to the Assistant General Manager – Business Systems and Customer Service, Riverside Public Utilities, 3750 University Avenue, 5th floor, Riverside, CA 92501. Additional financial information can also be obtained by visiting www.RiversidePublicUtilities.com. 94 MANAGEMENT’S DISCUSSION & ANALYSIS: WATER97
WATER UTILITY:

FINANCIAL STATEMENTS

STATEMENTS OF NET POSITION
June 30,
2023
June 30,
2022
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES (in thousands) NON-CURRENT ASSETS:

Capital assets:

Utility plant, net of accumulated depreciation (Note 3) $ 513,313 $ 508,294 Lease and subscription assets, net of amortization (Note 3 & 11) 28 16 Total capital assets 513,341 508,310
Restricted assets:

Cash and cash equivalents at fiscal agent (Note 2) 55,488 4,666 Total non-current restricted assets 55,488 4,666
Other non-current assets:

Regulatory assets 1,404 880
Leases receivable (Note 11) 84,385 82,983
Net pension asset (Note 6) - 8,809
Other long-term assets 2,625 2,925
Total other non-current assets 88,414 95,597
Total non-current assets: 657,243 608,573
CURRENT ASSETS:

Unrestricted assets:

Cash and cash equivalents (Note 2) 49,191 49,076
Accounts receivable, less allowance for doubtful accounts 2023 $930; 2022 $917 11,019 13,004
Accrued interest receivable 343 248
Leases receivable (Note 11) 1,001 425
Prepaid expenses 212 199
Other current assets 300 300
Total unrestricted current assets 62,066 63,252
Restricted assets:

Cash and cash equivalents (Note 2) 8,933 7,557
Water Conservation Programs - cash and cash equivalents (Note 2) 3,545 3,330 Water Conservation Programs receivable 134 172
Total restricted current assets 12,612 11,059
Total current assets 74,678 74,311
Total assets 731,921 682,884
DEFERRED OUTFLOWS OF RESOURCES:

Deferred outflows related to pension (Note 6) 11,588 3,080 Deferred outflows related to other postemployment benefits (Note 7) 644 727 Changes in derivative values - 812
Loss on refunding 4,758 5,028
Total deferred outflows of resources 16,990 9,647
Total assets and deferred outflows of resources $ 748,911 $ 692,531 See accompanying notes to the financial statements
95 FINANCIAL STATEMENTS: WATER
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FINANCIAL STATEMENTS

STATEMENTS OF NET POSITION
June 30,
2023
June 30,
2022
NET POSITION, LIABILITIES AND DEFERRED INFLOWS OF RESOURCES (in thousands) NET POSITION:

Net investment in capital assets $ 295,560 $ 293,641
Restricted for:

Debt service (Note 8) 8,933 7,557
Water Conservation Programs 3,545 3,431
Unrestricted 19,375 17,675
Total net position 327,413 322,304
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (Note 4) 290,760 239,544 OTHER NON-CURRENT LIABILITIES:

Compensated absences (Note 5) 527 668
Net pension liability (Note 6) 12,854 -
Other postemployment benefits liability (Note 7) 3,872 4,125 Derivative instruments (Note 4) 1,377 2,646
Regulatory liability 4,357 4,096
Lease liability (Note 11) 7 11
SBITA liability (Note 11) 2 -
Total other non-current liabilities 22,996 11,546
CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS:

Accrued interest payable 2,609 2,009
Water Conservation Programs payable 135 71
Current portion of long-term obligations (Note 4) 9,827 8,510 Total current liabilities payable from restricted assets 12,571 10,590 CURRENT LIABILITIES:

Accounts payable and other accruals 3,913 4,410
Compensated absences (Note 5) 1,958 1,905
Customer deposits 1,034 1,022
Unearned revenue 52 1,145
Other postemployment benefits liability 171 161
Current portion of long-term obligations (Note 4) 1,649 1,685 Lease liability (Note 11) 5 5
SBITA liability (Note 11) 15 -
Total current liabilities 8,797 10,333
Total liabilities 335,124 272,013
DEFERRED INFLOWS OF RESOURCES:

Deferred inflows related to pension (Note 6) 1,187 14,814 Deferred inflows related to other postemployment benefits (Note 7) 889 562 Changes in derivative values 196 -
Lease related items (Note 11) 84,102 82,838
Total deferred inflows of resources 86,374 98,214
Total net position, liabilities and deferred inflows of resources $ 748,911 $ 692,531 See accompanying notes to the financial statements
96 FINANCIAL STATEMENTS: WATER99
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FINANCIAL STATEMENTS

STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION For the Fiscal Years
Ended June 30,
2023 2022
(in thousands)
OPERATING REVENUES:

Residential sales $ 44,185 $ 45,784
Commercial sales 23,430 24,635
Other sales 2,268 2,446
Water conveyance revenue 3,381 3,572
Water Conservation Programs 1,090 1,000
Other operating revenue 4,349 3,098
Total operating revenues before uncollectibles 78,703 80,535 Estimated uncollectibles, net of bad debt recovery (29) (413) Total operating revenues, net of uncollectibles 78,674 80,122 OPERATING EXPENSES:

Operations 34,956 29,391
Maintenance 6,805 6,242
Purchased energy 6,632 6,863
Water conservation 977 733
Depreciation 16,367 16,179
Amortization 20 11
Total operating expenses 65,757 59,419
Operating income 12,917 20,703
NON-OPERATING REVENUES (EXPENSES):

Investment (loss) income 3,613 61
Interest expense and fiscal charges (10,689) (9,471)
Gain on sale of assets 119 709
Other 3,170 3,957
Total non-operating revenues (expenses) (3,787) (4,744) Income (loss) before capital contributions and transfers 9,130 15,959 Capital contributions 4,149 5,693
Transfers out - contributions to the City's general fund (8,170) (7,708) Total capital contributions and transfers (4,021) (2,015) Change in net position 5,109 13,944
NET POSITION, BEGINNING OF YEAR 322,304 308,360
NET POSITION, END OF YEAR $ 327,413 $ 322,304
See accompanying notes to the financial statements
97 FINANCIAL STATEMENTS: WATER
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FINANCIAL STATEMENTS

STATEMENT OF CASH FLOWS
For the Fiscal Years
Ended June 30,
2023
0 2022
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:

Cash received from customers and users $ 79,617 $ 80,337 Cash paid to suppliers for goods and services (31,432) (32,039) Cash paid to employees for services (18,778) (15,499)
Net cash provided (used) by operating activities 29,407 32,799 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:

Transfers out - contributions to the City's general fund (8,170) (7,708) Debt service payment on pension obligation bonds (1,363) (1,075) Other non-operating receipts 484 1,496
Net cash provided (used) by non-capital financing activities (9,049) (7,287) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:

Purchase of utility plant (20,181) (22,738)
Proceeds from the sale of utility plant 130 713
Proceeds from revenue bonds, including premium 63,596 - Bond issuance costs (582) -
Principal paid on long-term obligations (7,148) (6,867) Interest paid on long-term obligations (10,074) (9,004) Capital contributions 2,932 3,590
Lease and subscription payments (20) (5)
Net cash provided (used) by capital and related financing activities 28,653 (34,311) CASH FLOWS FROM INVESTING ACTIVITIES:

Income (loss) from investments 3,517 (101)
Net increase (decrease) in cash and cash equivalents 52,528 (8,900) Cash and cash equivalents, beginning of year (including $15,553 and $30,582 at June 30, 2022 and June 30, 2021, respectively, reported in restricted accounts) 64,629 73,529 Cash and cash equivalents, end of year (including $67,966 and $15,553 at June 30, 2023 and June 30, 2022, respectively, reported in restricted accounts) $ 117,157 $ 64,629 See accompanying notes to the financial statements
98 FINANCIAL STATEMENTS: WATER101
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FINANCIAL STATEMENTS

STATEMENT OF CASH FLOWS
For the Fiscal Years
Ended June 30,
2023
0 2022
(in thousands)

RECONCILIATION OF OPERATING INCOME TO NET CASH PROVIDED (USED) BY

OPERATING ACTIVITIES
Operating income (loss) 12,917 20,703

ADJUSTMENTS TO RECONCILE OPERATING INCOME (LOSS) TO NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES:

Depreciation 16,367 16,179
Amortization 20 11
(Increase) decrease in accounts receivable (146) (227)
(Increase) decrease in utility billed receivable 1,782 (242) (Increase) decrease in utility unbilled receivable 243 39 (Increase) decrease in intergovernmental receivable 106 1,846 (Increase) decrease in Water Conservation Programs receivable 38 (20) (Increase) decrease in prepaid items (13) 39
Increase (decrease) in accounts payable (928) 26
Increase (decrease) in accrued payroll 28 180
Increase (decrease) in retainage payable 403 240
Increase (decrease) in compensated absences (88) (146)
Increase (decrease) in unearned revenue (1,093) (1,202) Increase (decrease) in Water Conservation Programs payable 64 43 Increase (decrease) in deposits payable 12 9
Changes in net pension liability (asset) and related deferred inflows (outflows) of resources (472) (4,890)
Changes in OPEB liability and related deferred outflows and inflows of resources 167 211 Net cash provided (used) by operating activities $ 29,407 $ 32,799 SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:

Capital contributions - capital assets 1,218 2,103
Reduction of note payable including interest, offset by rent credit 1,974 1,890 See accompanying notes to the financial statements
99 FINANCIAL STATEMENTS: WATER
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NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Water Utility exists under, and by virtue of, the City of Riverside (the City) Charter enacted in 1883. The Water Utility is responsible for the production, transmission and distribution of water for sale in the City, except for certain areas served by another water utility. The accompanying financial statements present only the financial position and the results of operations of the Water Utility, which is an enterprise fund of the City, and are not intended to present fairly the financial position and results of operations of the City in conformity with generally accepted accounting principles. However, certain disclosures are for the City as a whole, since such information is generally not available for the Water Utility on a separate fund basis. All amounts, unless otherwise indicated, are expressed in thousands of dollars.

BASIS OF ACCOUNTING
The Water Utility uses the accrual basis of accounting as required for enterprise funds with accounting principles generally accepted in the United States of America as applicable to governments. The accounting records of the Water Utility are also in conformity with the Uniform System of Accounts prescribed by the California Public Utilities Commission. The Water 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 and expenses generally result from providing services and producing and delivering goods in connection with an enterprise fund’s principal ongoing operations. The principal operating revenues of the Water Utility are charges to customers for water 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 are reported as non-operating revenues and expenses.

IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENTS
The following new Governmental Accounting Standards Board (GASB) pronouncements were effective and have been implemented for fiscal year 2022-2023 audit:

GASB Statement No. 94, Public-Private and Public-Public Partnerships and Availability Payment Arrangement - A Public- Private and Public-Public Partnerships (PPP) is an arrangement in which a government (the transferor) contracts with an operator (a governmental or nongovernmental entity) to provide public services by conveying control of the right to operate or use a nonfinancial asset, such as infrastructure or other capital asset (the underlying PPP asset), for a period of time in an exchange or exchange-like transaction. Some PPPs meet the definition of a service concession arrangement (SCA) in which (1) the operator collects and is compensated by fees from third parties; (2) the transferor determines or has the ability to modify or approve which services the operator is required to provide, to whom the operator is required to provide the services, and the prices or rates that can be charged for the services; and (3) the transferor is entitled to significant residual interest in the service utility of the underlying PPP asset at the end of the arrangement. This Statement also provides guidance for accounting and financial reporting for availability payment arrangements (APAs). An APA is an arrangement in which a government compensates an operator for services that may include designing, constructing, financing, maintaining, or operating an underlying nonfinancial asset for a period of time in an exchange or exchange-like transaction.

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

USE OF ESTIMATES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during a reporting period. Accordingly, actual results could differ from those estimates.

REVENUE RECOGNITION
The Water Utility customers are billed monthly. Unbilled water service charges, including the Water Conservation Programs, are recorded at year-end and are included in accounts receivable. Unbilled accounts receivable totaled $3,456 at June 30, 2023, and $3,703 at June 30, 2022.

An allowance for doubtful accounts is maintained for utility and miscellaneous accounts receivable. The balance in this account is adjusted at fiscal year-end to approximate the amount anticipated to be uncollectible.

WATER UTILITY PLANT AND DEPRECIATION
The Water Utility defines capital assets as assets with an initial, individual cost of more than five thousand dollars and an estimated useful life in excess of one year. Utility plant assets are valued at historical costs or estimated historical cost, 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 valued at estimated fair value on the date contributed. The cost of relatively minor replacements is included in maintenance expense. Intangible assets that cost more than one hundred thousand dollars with useful lives of at 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 estimated useful lives are as follows:

Supply, pumping and treatment plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................20-50 years Transmission and distribution plant................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................25-50 years General plant and equipment................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-50 years Intangibles................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................5-15 years

RESTRICTED ASSETS
Proceeds of revenue bonds yet to be used for capital projects, as well as certain resources set aside for debt service, are classified 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 as restricted assets because their use is legally restricted for a specific purpose. Generally, the Water Utility will first apply restricted 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. This surcharge was approved by the City Council and was phased in over a three-year period with a 0.5 percent, 1.0 percent and 1.5 percent surcharge effective June 1, 2004, 2005 and 2006, respectively, to be in effect for services rendered on or after June 1, 2004 through May 31, 2014. On April 22, 2014, the City Council approved continuation of the 1.5 percent surcharge effective for the next ten years. The programs and services offered include conservation, education, and water use efficiency programs; and research, development and demonstration programs to advance science and technology with respect to water conservation. The activity associated with the surcharge is reflected in the accompanying financial statements on the Statements of Net Position, Statements of Revenues, Expenses and Changes in Net Position, and Statements of Cash Flows.

CASH AND CASH EQUIVALENTS
For the Statements of Cash Flows, cash and cash equivalents include all unrestricted and restricted highly liquid investments with original purchase maturities of three months or less, and all bond construction proceeds available for capital projects held at fiscal agent. Pooled cash and investments in the City’s Treasury represent monies in a cash management pool. Such accounts are similar in nature to demand deposits and are classified as cash equivalents for the purpose of presentation in the Statements of Cash Flows. 101
NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

CASH AND INVESTMENTS
In accordance with the Water Utility policy, the Water Utility’s cash and investments, except for cash and investments with fiscal agents, are invested in a pool managed by the Treasurer of the City. Cash accounts of all funds are pooled for investment purposes to enhance safety and liquidity, while maximizing interest earnings. The Water Utility does not own specific, identifiable investments of the pool. The pooled interest earned is allocated monthly based on the month end cash balances.

The Water Utility values its cash and investments in accordance with provisions of GASB Statement No. 72, Fair Value Measurement and Application, which requires governmental entities to use valuation techniques that are appropriate under the circumstances and for which sufficient data are available to measure fair value. The techniques should be consistent with one or more of the following approaches: the market approach, the cost approach or the income approach. Valuation includes 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 Water Utility does not value any of its investments using level 3 inputs.

City-wide information concerning cash and investments as of June 30, 2023, including authorized investments, fair value measurement and application, custodial credit risk, credit and interest rate risk for debt securities and concentration of investments, carrying amount and market value of deposits and investments can be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report.

DESIGNATED CASH RESERVES
The Riverside Public Utilities Cash Reserve Policy establishes several designated cash reserves in the Water Utility for strategic purposes. Designated reserves are set aside for specific purposes determined by the Board of Public Utilities and City Council. Designated reserves may be held for capital or operating purposes.

Designated cash reserve balances as of June 30, 2023 and 2022 were as follows: Property Reserve $5,926 and $5,804, Recycled Water Reserve $1,013 and $1,158, Customer Deposits $803 and $832, and Capital Repair and Replacement Reserve $2,378 and $2,363, respectively. The combined total for these reserves was $10,120 and $10,157 at June 30, 2023 and 2022, respectively, and is included as a component of unrestricted cash and cash equivalents in the accompanying Statements of Net Position.

DERIVATIVES
The Water Utility accounts for derivative instruments using GASB Statement No. 53, Accounting and Financial Reporting for Derivative Instruments (GASB 53). This Statement requires the Water Utility to report its derivative instruments at fair value. Changes in fair value for effective hedges are to be reported as deferred inflows and outflows of resources on the Statements 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 of Revenue, Expenses and Changes in Net Position.

The Water Utility has determined that its interest rate swaps associated with variable rate obligations are derivative instruments under GASB 53. See Note 4 Long-Term Obligations for further discussion related to the Water Utility’s interest rate swaps.

BOND PREMIUMS/DISCOUNTS AND GAINS/LOSSES ON REFUNDING
Bond 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 are reported net of the applicable bond premium or discount. Gains/losses on refunding are reported as deferred inflows or outflows of resources.

CUSTOMER DEPOSITS
The City holds customer deposits as security for the payment of utility bills and plan check fee deposits for future water connection. The Water Utility’s portion of these deposits as of June 30, 2023 and 2022 was $1,034 and $1,022, respectively.
102NOTES TO THE FINANCIAL STATEMENTS: WATER105
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NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

COMPENSATED ABSENCES
The accompanying financial statements include accruals for salaries, fringe benefits and compensated absences due to employees at June 30, 2023 and 2022. The Water Utility treats compensated absences due to employees as an expense and a liability of which a current portion is included in accounts payable and other accruals in the accompanying Statements of Net Position. The amount accrued for compensated absences was $2,485 at June 30, 2023, and $2,573 at June 30, 2022.

Employees receive 10 to 25 vacation days per year based upon length of service. A maximum of two years vacation accrual may be accumulated, and unused vacation is paid in cash upon separation.

INSURANCE PROGRAMS
The Water Utility participates in a self-insurance program for workers’ compensation and general liability coverage that is administered by the City. The Water Utility pays an amount to the City based on actuarial estimates of the amounts needed to fund prior and current year claims and incidents that have been incurred but not reported. The City maintains property 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 for risks for the year ended June 30, 2023, may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report.

Although the ultimate amount of losses incurred through June 30, 2023 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 the Water Utility were $786 and $975 for the years ended June 30, 2023 and 2022, respectively. Any losses above the City’s reserves would be covered through increased rates charged to the Water Utility in future years.

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 determined on the same basis as they are reported by CalPERS. For this purpose, benefit payments (including refunds of employee contributions) are recognized when due and payable in accordance with the benefit terms. Investments are reported at fair value. Further details of employee retirement plan can be found in Note 6.

OTHER POSTEMPLOYMENT BENEFITS (OPEB)
OPEB refers to the benefits, other than pensions, that the City provides as part of an employee’s retirement benefits. The net OPEB obligation is defined as the liability of employers contributing to employees for benefits provided through a defined 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 RESOURCES
When applicable, the Statements of Net Position will report a separate section for deferred outflows of resources. Deferred outflows 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 of changes in derivative values, loss on refunding, and deferred outflows related to pension and OPEB which include pension contributions 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. 103NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

DEFERRED OUTFLOWS AND DEFERRED INFLOWS OF RESOURCES (CONTINUED) Conversely, deferred inflows of resources represent inflows of resources (acquisition of net position) that apply to future periods, therefore, are not recognized as an inflow of resources (revenue) until that time. Deferred inflows of resources consist of changes in derivative values, lease related items, deferred inflows related to pension and OPEB which include changes in assumptions, differences between expected and actual experience, and net differences between projected and actual earnings on pension plan investments.

REGULATORY ASSETS AND DEFERRED REGULATORY CHARGES
In accordance with regulatory accounting criteria set forth in GASB Codification (GASB Statement No. 62), enterprise funds that are used to account for rate-regulated activities are permitted to defer certain expenses and revenues that would otherwise be recognized when incurred, provided that the Water Utility is recovering or expects to recover or refund such amounts in rates charged to its customers. Accordingly, regulatory assets and/or deferred regulatory charges related to debt issuance costs have been recognized in the Statements of Net Position.

NET POSITION
The Water Utility’s net position represents the difference between assets and deferred outflows of resources less liabilities and deferred inflows of resources, which is classified into the following three components:

Net investment in capital assets – this component consists of capital assets (net of accumulated depreciation) reduced by the outstanding balance of any bonds or other borrowings that are attributable to the acquisition, construction, or improvement of those assets, excluding unspent bond proceeds.

Restricted – this component represents restricted assets less liabilities and deferred inflows related to those assets.

Unrestricted – this component consists of net position that does not meet the definition of “restricted” or “net investment in capital assets.”
CONTRIBUTIONS TO THE CITY’S GENERAL FUND
Pursuant to the City of Riverside Charter and the voter approval of Measure A on June 4, 2013, the Water Utility may transfer up to 11.5 percent of prior year’s gross operating revenues, including adjustments, to the City’s general fund. In fiscal years ended June 30, 2023 and 2022, $8,170 and $7,708, respectively, was transferred, representing 11.5 percent.

Additional information can be found in Note 10 of the accompanying financial statements.

BUDGETS AND BUDGETARY ACCOUNTING
The Water Utility presents, and the City Council adopts, a biennial budget. The proposed budget includes estimated expenses and forecasted revenues. The City Council generally adopts the Water Utility’s budget in June biennially via resolution. Per City Council direction, the Water Utility transitioned from an incremental budget methodology to a priority- based budgeting methodology in fiscal year 2022-2023.

LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS Leases are defined by the general government as the right to use an underlying asset. As lessee, the Water Utility recognizes a lease liability and a lease asset at the beginning of a lease period unless the lease is considered a short-term lease or transfers ownership of the underlying asset. Lease assets are measured based on the net present value of the future lease payments at inception, using the weighted average cost of capital, which approximate the incremental borrowing rate. Re-measurement of a lease liability occurs when there is a change in the lease term and/or other changes that are likely to have a significant impact on the lease liability. The Water Utility calculates the amortization of the discount on the lease liability and report that amount as outflows of resources. Payments are allocated first to accrued interest liability and then to the lease liability. Variable lease payments based on the usage of the underlying assets are not included in the lease liability calculations but are recognized as outflows of resources in the period in which the obligation was incurred. As lessor, the Water Utility recognizes a lease receivable. The lease receivable is measured using the net present value of future lease payments to be received for the lease term and deferred inflow of receivables at the 104
NOTES TO THE FINANCIAL STATEMENTS: WATER107
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)
beginning of the lease term. Periodic amortization of the discount on the receivable are reported as interest revenue for that period. Deferred inflows of resources are recognized as inflows on a straight-line basis over the term of the lease. This recognition 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 contract price, lease term, and adding or removing an underlying asset to the lease agreements. In the case of a partial or full lease termination, the carrying value of the lease receivable and the related deferred inflow of resources will be reduced and will include a gain or loss for the difference. For lease contracts that are short-term, the Water Utility recognizes short-term lease payments as inflows of resources (revenues) based on the payment provisions of the lease contract. Liabilities are only recognized if payments are received in advance, and receivables are only recognized if payments are received subsequent 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 use another party’s IT software, alone or in combination with tangible capital assets, as specified in the contract for a period of time in an exchange or exchange-like transaction. To determine whether a contract conveys control of the right to use the underlying IT assets, the Water Utility assesses both the right to obtain the present service capacity from use of the underlying IT assets 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 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 relevant factors, that the government will exercise that option. Periods for which both the government and the SBITA vendor have an option to terminate the SBITA without permission from the other party (or if both parties have to agree to extend) are cancelable periods and are excluded from the subscription term. Additional disclosures regarding SBITAs are in Note 11.

RECLASSIFICATIONS
Certain reclassifications have been made to prior year’s financial statements to conform with the current year’s presentation. Such reclassifications have no effect on the net position or the changes in net position. 105
NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

2. CASH AND INVESTMENTS
Cash and investments at June 30, 2023 and 2022, consist of the following (in thousands):

June 30, 2023 June 30, 2022
Fair Value
Equity interest in City Treasurer's investment pool $ 61,669 $ 59,963 Cash and cash equivalents at fiscal agent 55,488 4,666
Total cash and investments $ 117,157 $ 64,629
The amounts above are reflected in the accompanying financial statements as:

June 30, 2023 June 30, 2022
Unrestricted cash and cash equivalents $ 49,191 $ 49,076 Restricted cash and cash equivalents 12,478 10,887
Restricted cash and cash equivalents at fiscal agent 55,488 4,666 Total cash and investments $ 117,157 $ 64,629
The investment types in the tables below related to the Water Utility’s investments in the City Treasurer’s investment pool represent the Water Utility’s prorated share of the investment types in the investment pool and do not represent ownership interests in the individual investments.
106
NOTES TO THE FINANCIAL STATEMENTS: WATER109
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 accepted accounting principles. The Water Utility has the following recurring fair value measurements as of June 30, 2023 and 2022:

Investment Type
June 30, 2023
Fair Value
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Investments
not Subject to
Fair Value
Hierarchy
Held by fiscal agent
Money market funds $ 55,488 $ - $ - $ - $ 55,488
City Treasurer's investment pool1
Money market funds 1,116 - - - 1,116
Joint powers authority pools 11,896 - - - 11,896
Mortgage pass-through securities 2,031 - 2,031 - -
Asset-backed securities 5,155 - 5,155 - -
US Treasury obligations 17,853 - 17,853 - -
Federal agency obligations 8,538 - 8,538 - -
Medium-term corporate notes 12,849 - 12,849 - -
Supranational securities 2,231 - 2,231 - -
Total $ 117,157 $ - $ 48,657 $ - $ 68,500
Investment Type
June 30, 2022
Fair Value
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Investments
not Subject to
Fair Value
Hierarchy
Held by fiscal agent
Money market funds $ 4,666 $ - $ - $ - $ 4,666
City Treasurer's investment pool1
Money market funds 1,663 - - - 1,663
Joint powers authority pools 9,334 - - - 9,334
Local agency investment fund 7,092 - - - 7,092
Mortgage pass-through securities 2,345 - 2,345 - -
Asset backed securities 4,743 - 4,743 - -
US Treasury obligations 13,540 - 13,540 - -
Federal agency obligations 8,005 - 8,005 - -
Medium-term corporate notes 10,519 - 10,519 - -
Supranational securities 2,441 - 2,441 - -
Negotiable certificate of deposit 281 - 281 - -
Total $ 64,629 $ - $ 41,874 $ - $ 22,755
1Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report. 107
NOTES 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, 2023 and 2022, are as follows:

Remaining Maturity (in Months)
Investment Type
June 30, 2023
Fair Value
12 Months
or Less 13 to 36 Months 37 to 60 Months
Held by fiscal agent
Money market funds $ 55,488 $ 55,488 $ - $ -
City Treasurer's investment pool1
Money market funds 1,116 1,116 - -
Joint powers authority pools 11,896 11,896 - -
Mortgage pass-through securities 2,031 320 737 974
Asset-backed securities 5,155 57 2,299 2,799
US Treasury obligations 17,853 2,938 5,274 9,641
Federal agency obligations 8,538 2,026 5,187 1,325
Medium-term corporate notes 12,849 641 6,992 5,216
Supranational securities 2,231 - 2,231 -
Total $ 117,157 $ 74,482 $ 22,720 $ 19,955
Remaining Maturity (in Months)
Investment Type
June 30, 2022
Fair Value
12 Months
or Less 13 to 36 Months 37 to 60 Months
Held by fiscal agent
Money market funds $ 4,666 $ 4,666 $ - $ -
City Treasurer's investment pool1
Money market funds 1,663 1,663 - -
Joint powers authority pools 9,334 9,334 - -
Local agency investment fund 7,092 7,092 - -
Mortgage pass-through securities 2,345 654 1,365 326
Asset-backed securities 4,743 - 2,544 2,199
US Treasury obligations 13,540 1,628 6,576 5,336
Federal agency securities 8,005 1,248 5,017 1,740
Medium-term corporate notes 10,519 482 4,727 5,310
Supranational securities 2,441 - 848 1,593
Negotiable certificate of deposit 281 281 - -
Total $ 64,629 $ 27,048 $ 21,077 $ 16,504
1Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report. 108
NOTES TO THE FINANCIAL STATEMENTS: WATER111
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

2. CASH AND INVESTMENTS (CONTINUED)
Presented below is the actual rating as of June 30, 2023 and 2022 for each investment type:

Rating as of Year End
Investment Type
June 30, 2023
Fair Value AAA AA A Unrated
Held by Fiscal Agent
Money Market Funds $ 55,488 $ 55,488 $ - $ - $ -
City Treasurer's investment pool1
Money market funds 1,116 1,116 - - -
Joint powers authority pools 11,896 - - - 11,896
Mortgage pass-through securities 2,031 2,031 - - -
Asset-backed securities 5,155 3,898 - - 1,257
US Treasury obligations 17,853 17,853 - - -
Federal agency obligations 8,538 7,229 - - 1,309
Medium-term corporate notes 12,849 406 4,447 6,273 1,723 Supranational securities 2,231 1,149 - - 1,082
Total $ 117,157 $ 89,170 $ 4,447 $ 6,273 $ 17,267
Rating as of Year End
Investment Type
June 30, 2022
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds $ 4,666 $ - $ - $ - $ 4,666
City Treasurer's investment pool1
Money market funds 1,663 1,297 - - 366
Joint powers authority pools 9,334 - - - 9,334
Local agency investment fund 7,092 - - - 7,092
Mortgage pass-through securities 2,345 2,345 - - -
Asset backed securities 4,743 3,777 - - 966
US Treasury obligations 13,540 13,540 - - -
Federal agency obligations 8,005 8,005 - - -
Medium-term corporate notes 10,519 - 3,733 5,740 1,046
Supranational securities 2,441 1,262 - - 1,179
Negotiable certificate of deposit 281 - - 281 -
Total $ 64,629 $ 30,226 $ 3,733 $ 6,021 $ 24,649
1Additional information on investment types, fair value measurement, interest rate risk and credit risk may be found in the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report. 109
NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

3. CAPITAL ASSETS
The following is a summary of changes in utility plant and lease and subscription assets during the fiscal years ended June 30, 2023 and 2022 (in thousands):

Balance
As of
6/30/2021 Additions
Retirements/
Transfers
Balance
As of
6/30/2022 Additions
Retirements/
Transfers
Balance
As of
6/30/2023
Source of supply $ 78,102 $ 2,784 $ - $ 80,886 $ 1,046 $ - $ 81,932 Pumping 35,162 51 - 35,213 618 (3) 35,828
Treatment 44,768 26 - 44,794 1,066 - 45,860
Transmission and distribution 535,520 12,358 (8,222) 539,656 13,827 (1,365) 552,118 General 16,458 1,970 (153) 18,275 704 (254) 18,725
Intangible 4,171 10 - 4,181 - - 4,181
Depreciable utility plant 714,181 17,199 (8,375) 723,005 17,261 (1,622) 738,644 Less accumulated depreciation
Source of supply (23,678) (1,977) - (25,655) (2,054) - (27,709) Pumping (15,016) (752) - (15,768) (756) - (16,524)
Treatment (17,646) (1,280) - (18,926) (1,282) - (20,208) Transmission and distribution (203,053) (11,338) 8,218 (206,173) (11,578) 1,352 (216,399) General (13,426) (487) 152 (13,761) (576) 248 (14,089)
Intangible (3,677) (344) - (4,021) (122) - (4,143)
Accumulated depreciation (276,496) (16,178) 8,370 (284,304) (16,368) 1,600 (299,072) Net depreciable utility plant 437,685 1,021 (5) 438,701 893 (22) 439,572 Land 20,841 - - 20,841 - - 20,841
Intangible, non-amortizable 10,975 - (130) 10,845 - - 10,845 Construction in progress 30,135 22,864 (15,092) 37,907 20,204 (16,056) 42,055 Nondepreciable utility plant 61,951 22,864 (15,222) 69,593 20,204 (16,056) 73,741 Total utility plant, net $ 499,636 $ 23,885 $ (15,227) $ 508,294 $ 21,097 $ (16,078) $ 513,313 Lease and subscription assets, being
amortized 1
Machinery and equipment-Intangible - 21 - 21 - - 21
Subscription-based information technology
arrangements - - - - 32 - 32
Total lease and subscription assets - 21 - 21 32 - 53
Less lease accumulated amortization
Machinery and equipment-Intangible - (5) - (5) (5) - (10) Subscription-based information technology
arrangements - - - - (15) - (15)
Total lease accumulated amortization - (5) - (5) (20) - (25) Total lease and subscription assets, net - 16 - 16 12 - 28 Total capital assets
being depreciated, net $ 499,636 $ 23,901 $ (15,227) $ 508,310 $ 21,109 $ (16,078) $ 513,341 1GASB 87 Leases was implemented effective July 1, 2021. GASB 96 Subscription-Based Information Technology Arrangements (SBITA) was implemented effective July 1, 2022. For additional information, refer to Notes 1 and 11. 110
NOTES TO THE FINANCIAL STATEMENTS: WATER113
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS
The following is a summary of changes in long-term obligations during the fiscal years ended June 30, 2023 and 2022 (in thousands):

Balance
As of
6/30/2021 Additions Reductions
Balance
As of
6/30/2022 Additions Reductions
Balance
As of
6/30/2023
Due Within
One Year
Revenue bonds $ 217,306 $ - $ (7,644) $ 209,662 $ 63,596 $ (7,964) $ 265,294 $ 7,950 Pension obligation bonds 22,363 - (1,076) 21,287 - (1,363) 19,924 1,640 Direct Borrowings:

Financed purchases 1,445 - (227) 1,218 - (233) 985 237
Notes payable 18,138 - (1,499) 16,639 - (1,539) 15,100 1,499 Contracts payable - Water stock
acquisition rights 1,067 - (134) 933 - - 933 150
Total long-term obligations $ 260,319 $ - $ (10,580) $ 249,739 $ 63,596 $ (11,099) $ 302,236 $ 11,476 Long-term debt consists of the following (in thousands):

CONTRACTS PAYABLE
June 30, 2023 June 30, 2022
Water Stock Acquisitions: Payable to various water companies $ 933 $ 933 Total contracts payable 933 933

PENSION OBLIGATION BONDS PAYABLE
June 30, 2023 June 30, 2022
$31,960 2017 Taxable Pension Obligation Bonds Series A: fixed rate bonds issued by the City due in annual installments from $2,910 to $3,580 through June 2027, with coupons from 1.3 to 3.1 percent. The Water Utility's proportional share of the outstanding debt is 10.7 percent. $ 1,465 $ 1,807
$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 $14,625 through June 2045, with coupons from 1.6 to 3.9 percent.

The Water Utility's proportional share of the outstanding debt is 10.2 percent. 18,459 19,480
Total pension obligation bonds payable 19,924 21,287

REVENUE BONDS PAYABLE
June 30, 2023 June 30, 2022
$67,790 2009 Water Revenue Series B Bonds: fixed rate, federally taxable, Build America Bonds due in annual principal installments from $2,475 to $4,985 from October 1, 2021 through October 1, 2039, interest from 3.3 to 4.1 percent.
$ 62,760 $ 65,315
$59,000 2011 Water Revenue/Refunding Series A Bonds: variable rate bonds due in annual principal installments from $2,375 to $3,950 through October 1, 2035. Interest rate is subject to daily repricing (net interest rate, including swaps, at June 30, 2019 was 3.2 percent). Partially refunded $26,900 on April 1, 2019 with 2019A Water Refunding Bonds.
24,050 24,050
$114,229 2019 Water Revenue Refunding Series A Bonds: fixed rate bonds due in annual principal installments from $1,680 to $8,455 through October 1, 2048, interest of 5.0 percent. 98,465 102,825
$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. 58,025 -
Total water revenue bonds payable 243,300 192,190
Total water revenue bonds, pension obligation bonds and contracts payable 264,157 214,410 Unamortized bond premium 21,994 17,472
Total water revenue bonds, pension obligation bonds and contracts payable, including bond premium 286,151 231,882 Less current portion (9,740) (8,428)
Total long-term water revenue bonds, pension obligation bonds and contracts payable $ 276,411 $ 223,454 111
NOTES 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, which the City issued in 2005 and refinanced a portion in May 2017. The bond proceeds were deposited with CalPERS to fund 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 bonds were issued to reduce the City's unfunded pension liability in both the City's Miscellaneous and Safety CalPERS plans. It is estimated 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 due in annual installments from $1,285 to $14,625 through June 2045, with coupons from 1.6 to 3.9 percent. The Water Utility's proportional share of the miscellaneous plan is 10.2 percent.

The Water Utility's proportional share of the outstanding principal amount of both pension obligation bonds was $19,924 and $21,287 as of June 30, 2023 and 2022, respectively. For more discussion relating to the City's pension obligation bond issuance, see the notes to the City's financial statements in the City's Annual Comprehensive Financial Report for the fiscal year ended June 30, 2023.

Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Fiscal Year Principal Interest Total
2024 $ 1,640 $ 642 $ 2,282
2025 1,815 605 2,420
2026 1,867 562 2,429
2027 1,793 514 2,307
2028 1,182 465 1,647
2029-2033 4,282 1,900 6,182
2034-2038 4,823 1,033 5,856
2039-2043 2,522 224 2,746
Total $ 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 aggregate amount of Bond Obligation may, by written notice to the City, declare the entire unpaid principal and accreted value of the bonds due and payable should the City fail to pay its debts as they become due or upon the entry of any decree or order of bankruptcy of the City.
$58,025 Water Revenue Bonds Series A. The bonds were issued in December 2022 to fund short-term and long-term capital projects. Interest on the bonds is 5%, payable in April and October of each year. Principal payments are due in annual 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. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Fiscal Year Principal Interest Total
2024 $ 7,950 $ 11,050 $ 19,000
2025 8,460 10,664 19,124
2026 8,840 10,257 19,097
2027 9,245 9,831 19,076
2028 9,665 9,385 19,050
2029-2033 54,430 39,883 94,313
2034-2038 66,100 27,022 93,122
2039-2043 35,515 13,817 49,332
2044-2048 24,110 7,878 31,988
2049-2053 18,985 2,193 21,178
Premium 21,994 - 21,994
Total $ 265,294 $ 141,980 $ 407,274
112
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Remaining revenue bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Remaining revenue bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Remaining revenue bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

Remaining revenue bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2023 are as follows (in thousands):

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)
The Water Utility has a number of debt issuances (revenue bonds) outstanding that are collateralized by the pledging of water revenues. The amount and term of the remainder of these commitments are indicated in the revenue bonds payable and annual debt service requirements to maturity tables presented within this Note 4. The purpose of the debt issuances was for the financing of various Water Utility capital improvement projects. For June 30, 2023 and 2022, debt service payments as a percentage of the pledged gross revenue, net of certain expenses where so required by the debt agreement, are indicated in the table below. The debt service coverage ratios also approximate the relationship of the debt service to pledged revenue for the remainder of the term of the commitment.

Fiscal Year Ended
Description of
Pledged Revenues
Annual Amount of
Pledged Revenue
(net of expenses) 1, 2, 3
Annual Debt Service
Payments
Debt Service
Coverage
Ratio
June 30, 2023 Water revenues $ 36,362 $ 18,848 1.93
June 30, 2022 Water revenues $ 37,986 $ 17,069 2.23
1Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of $(471) and $(4,891) for June 30, 2023 and 2022, respectively.
2Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $168 and $210 for June 30, 2023 and 2022, respectively.
3Includes GASB 87 Leases net revenue adjustment of $728 and $708 for June 30, 2023 and 2022, respectively.

LINE OF CREDIT
On 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 Electric and Water Utility Five-Year Rate Plan to manage rate increases by enabling the Water Utility to reduce cash levels while maintaining compliance with the Riverside Public Utilities Cash Reserve Policy. Under the terms and conditions of the agreement, the City may borrow up to $25,000 for purposes of the capital or operating financial needs of the Water System. There were no borrowings against the line as of June 30, 2023.

LETTERS OF CREDIT
The Water Utility’s Issue of the 2011A Water Revenue Bonds require an additional layer of security between the Water Utility and the purchaser of the bonds. The Water Utility has entered into the following letters of credit (LOC) in order to provide liquidity should all or a portion of the debt be optionally tendered to the remarketer without being successfully remarketed:

Debt Issue LOC Provider
LOC
Expiration
Date
Annual
Commitment
Fee
2011A Water Revenue Bonds PNC Bank, NA 2025 %0.230
To the extent that remarketing proceeds are insufficient or not available, tendered amounts will be paid from drawings made under an irrevocable direct-pay letter of credit.

INTEREST RATE SWAPS ON REVENUE BONDS
The Water Utility has one cash flow hedging derivative instrument, which is a pay-fixed swap. The swap was 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 the swap is included as part of the deferred loss on refunding associated with the new bonds. The swap was also employed as a hedge against the new debt. Hedge accounting was applied to that portion of the hedging relationship, which was determined to be effective. The negative fair value of the interest rate swaps related to the new hedging relationship has been recorded and deferred on the Statements of Net Position. 113
NOTES TO THE FINANCIAL STATEMENTS: WATER
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 is as follows:

Notional
Amount
Fair Value
as of
June 30, 2023
Change in
Fair Value
for Fiscal Year
2011 Water Refunding/Revenue Bonds Series A $ 24,050 $ (1,377) $ 1,269 Objective: In order to lower borrowing costs as compared to fixed-rate bonds, the Water Utility entered into an interest rate swap agreement in connection with its $59,000 2011 Water Refunding/Revenue Series A Bonds.

Terms: Per the existing swap agreement, the Water Utility pays the counterparty a fixed payment and receives a variable payment computed as 62.68 percent of the London Interbank Offering Rate (“LIBOR”) one-month index plus 12 basis points. The swap has a notional amount equal to the principal amount stated above. The notional value of the swap and principal amount of the associated debt decline by $1,475 to $3,950 until the debt is completely retired in fiscal year 2036.

The bonds and the related swap agreement for the 2011 Water Refunding/Revenue Series A Bonds mature on October 1, 2035. As of June 30, 2023, rates were as follows:

Interest rate swap: Terms Rates
Fixed payment to counterparty Fixed %3.20000
Variable payment from counterparty 62.68 LIBOR + 12bps %(0.72101) Net interest rate swap payments %2.47899
Variable-rate bond coupon payments %0.65145
Synthetic interest rate on bonds %3.13044
Fair value: As of June 30, 2023, in connection with the swap agreement, the transactions had a total negative fair value of $(1,377). Because the coupons on the Water Utility’s variable-rate bonds adjust to changing interest rates, the bonds do not have a corresponding fair value decrease. The fair value was developed by a pricing service 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. These payments are then discounted using the spot rates implied by the current yield curve for hypothetical zero-coupon bonds due on the date of each future net settlement of the swap.

Credit risk: As of June 30, 2023, the Water Utility was not exposed to credit risk because the swap had a negative fair value. The swap counterparty, J.P. Morgan Chase & Co. was rated A- by Standard & Poor's (S&P). To mitigate the potential for credit risk, the swap agreement requires the fair value of the swap to be collateralized by the counterparty with U.S. Government securities if the counterparty’s rating decreases to negotiated trigger points. Collateral would be posted with a third-party custodian. At June 30, 2023, there is no requirement for collateral posting for the outstanding swap.

Basis risk: As noted above, the swap exposes the Water Utility to basis risk should the relationship between LIBOR and the variable interest rates converge, changing the synthetic rate on the bonds. If a change occurs that results in the rates moving to convergence, the expected cost savings may not be realized.

Termination risk: The derivative contract uses the International Swap Dealers Association Master Agreement, which includes standard termination events, such as failure to pay and bankruptcy. The Schedule to the Master Agreement includes an “additional termination event.” That is, a swap may be terminated by the Water Utility if the counterparty’s credit quality falls below “BBB-” as issued by S&P. The Water Utility or the counterparty may terminate a swap if the other party fails to perform under the terms of the contract. If a swap is terminated, the variable-rate bond would no longer carry a synthetic interest rate. Also, if at the time of termination a swap has a negative fair value, the Water Utility would be liable to the counterparty for a payment equal to the swap’s fair value. 114
NOTES TO THE FINANCIAL STATEMENTS: WATER117
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

INTEREST RATE SWAPS ON REVENUE BONDS (CONTINUED)
Swap payments and associated debt: As of June 30, 2023, the debt service requirements of the variable- rate debt 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 Bonds
Fiscal Year
Ending
June 30, Principal Interest
Interest Rate
Swaps, Net Total
2024 $ - $ 164 $ 625 $ 789
2025 - 164 625 789
2026 - 164 625 789
2027 - 164 625 789
2028 - 164 625 789
2029-2033 12,575 619 2,357 15,551
2034-2038 11,475 100 379 11,954
Total $ 24,050 $ 1,539 $ 5,861 $ 31,450
Replacement of London Interbank Offering Rate (LIBOR): As of July 1, 2023, LIBOR is no longer an appropriate benchmark interest rate for a derivative instrument that hedges the interest risk for taxable debt for purposes of GASB Statement 53.

NOTE PAYABLE
Note payable consists of several agreements with Harvest A OSR, LLC, Stockbridge NLP, LLC, and related entities (collectively Hillwood) for their development of logistic centers located in the City of San Bernardino. As a part of these agreements, the Water Utility leases land to Hillwood and also purchased land from Hillwood with a subsequent lease- back to the entity. In addition, the agreements require Hillwood to relocate wells located on the properties as well as terminate an existing lease. In consideration of the cost of the land purchase, well relocations and lease termination, the Water Utility will make payments to Hillwood in the form of a credit with Hillwood’s rental payments to the Water Utility for the first 15 years of the leases. These agreements resulted in a total liability to the Water Utility of $15,100, as of June 30, 2023.

Estimated annual rent credits, which are adjusted annually based on Consumer Price Index (CPI), to be applied to the land purchase and well relocation agreements commencing in 2014 with an effective interest rate of 5.19 percent, are as follows (in thousands):

Fiscal Year Principal Interest Total
2024 $ 909 $ 442 $ 1,351
2025 1,028 392 1,420
2026 1,156 335 1,491
2027 1,296 272 1,568
2028 1,447 201 1,648
2029-2030 3,078 157 3,235
Total $ 8,914 $ 1,799 $ 10,713
115
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)

NOTES TO THE FINANCIAL STATEMENTS

4. LONG-TERM OBLIGATIONS (CONTINUED)
Estimated annual rent credits, which are adjusted annually based on CPI, to be applied to the well relocation agreement commencing in 2018 with an effective interest rate of 3.00 percent, are as follows (in thousands):

Fiscal Year Principal Interest Total
2024 $ 290 $ 98 $ 388
2025 300 89 389
2026 309 79 388
2027 319 70 389
2028 329 59 388
2029-2033 1,714 133 1,847
Total $ 3,261 $ 528 $ 3,789
Annual rent credits to be applied for the lease termination agreement commencing in 2018, are as follows (in thousands):

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

FINANCED PURCHASES
In fiscal year ended June 30, 2017, the Water Utility participated in the City’s purchase financing program for the acquisition of water system heavy vehicles and equipment. The heavy vehicles and equipment financed purchases are for a ten-year term of annual payments with an interest rate of 2.36 percent. Gross proceeds of $2,305 were received for the financing. The total liability with the current portion included in current portion of long-term obligations as of June 30, 2023 and 2022 was $985 and $1,218, respectively. The annual payments for the life of the agreements are $260 annually through fiscal year ending June 30, 2027. As of June 30, 2023 total outstanding payments are $1,039, with $985 representing principal and $54 representing interest.

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

Balance
As of
6/30/2021 Additions Reductions
Balance
As of
6/30/2022 Additions Reductions
Balance
As of
6/30/2023
Due Within One
Year
Compensated absences $ 2,719 $ 1,868 $ (2,014) $ 2,573 $ 1,940 $ (2,028) $ 2,485 $ 1,958 116
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

NOTES TO THE FINANCIAL STATEMENTS

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

NOTES TO THE FINANCIAL STATEMENTS

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

NOTES TO THE FINANCIAL STATEMENTS

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

NOTES TO THE FINANCIAL STATEMENTS

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

NOTES TO THE FINANCIAL STATEMENTS

Fiscal Year
Ending Principal Interest Total
2024 $ 300 $ - $ 300
2025 300 - 300
2026 300 - 300
2027 300 - 300
2028 300 - 300
2029-2033 1,425 - 1,425
Total $ 2,925 $ - $ 2,925

5. COMPENSATED ABSENCES
A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.

Below is a summary of changes in compensated absences for the Water Utility during the fiscal year.

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN

PLAN DESCRIPTION
The City contributes to CalPERS, an agent multiple employer 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 and administrative agent for participating public entities within the State of California. CalPERS issues a publicly available financial report that includes financial statements and required supplementary information for the cost sharing plans that are administered by CalPERS. Benefit provisions and all other requirements are established by state statute and City ordinance. A copy of CalPERS’ annual financial report may be obtained online at www.calpersca.gov. The Water Utility participates in the City’s Miscellaneous (non-safety) Plan (the Plan).

FUNDING POLICY
The City has contributed at the actuarially determined rate provided by CalPERS’ actuaries. Participants are required to contribute 8% of their annual covered salary. The City has a multiple tier retirement plan with benefits varying by plan. All permanent full-time and selected part-time employees are eligible for participation in CalPERS. Benefits vest after five years of service and are determined by a formula that considers the employee’s age, years of service and salary. Under the Plan, the City pays the employees’ contribution to CalPERS for employees hired on or before specific dates as follows:
 1st Tier –
 The retirement formula is 2.7% at age 55 for employees hired on or before October 18, 2011. Effective January 1, 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 employees were required to pay 2% of their pensionable income, with the City contributing the other 6%. Effective January 1, 2019, employees were required to pay an additional portion of their pensionable income. This portion is a three-year increase of 2% (2019), 2% (2020) and 2% (2021). As of 2021, 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 other 1%. Effective January 1, 2019, employees were required to pay an additional portion of their pensionable income. This portion is a two-year increase of 1% (2019) and 1% (2020). As of 2020, employees are contributing 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 before October 18, 2011. Effective November 1, 2017 employees were required to pay 2% of their total pensionable income with the City paying the remaining 6%. Effective each November 1st, employees will be required 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 their pensionable income.
 2nd Tier - 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 the employee must pay the normal cost to CalPERS which is currently at 7.75%. Classic members (CalPERS members 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. 117
NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

BENEFITS PROVIDED
CalPERS provides service retirement and disability benefits, annual cost of living adjustments and death benefits to plan members, who must be public employees and beneficiaries. Benefits are based on years of credited service, equal to one year of full-time employment. Members with five years of total service are eligible to retire at age 50 with statutorily reduced benefits. All members are eligible for non-duty disability benefits after five years of service. The death benefit is one of the following: the Basic Death Benefit, the 1959 Survivor Benefit Level III, or the Optional Settlement 2W Death Benefit. The cost of living adjustments for the Plan are applied as specified by the Public Employees’ Retirement Law.

EMPLOYEES COVERED
As of measurement date June 30, 2022 and June 30, 2021 , the following employees, City-wide, were covered by the benefit terms of the Plan:

ACTUARIAL ASSUMPTIONS
The total pension liabilities in the June 30, 2022 and 2021 actuarial valuations were determined using the following actuarial assumptions:
118
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

EMPLOYEES COVERED
As of measurement date June 30, 2022 and June 30, 2021 , the following employees, City-wide, were covered by the benefit terms of the Plan:

ACTUARIAL ASSUMPTIONS
The total pension liabilities in the June 30, 2022 and 2021 actuarial valuations were determined using the following actuarial assumptions:
118
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

EMPLOYEES COVERED
As of measurement date June 30, 2022 and June 30, 2021 , the following employees, City-wide, were covered by the benefit terms of the Plan:

ACTUARIAL ASSUMPTIONS
The total pension liabilities in the June 30, 2022 and 2021 actuarial valuations were determined using the following actuarial assumptions:
118
NOTES TO THE FINANCIAL STATEMENTS: WATER121
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

ACTUARIAL ASSUMPTIONS (CONTINUED)
Miscellaneous
Current Year
Miscellaneous
Prior Year
Valuation Date June 30, 2021 June 30, 2020
Measurement Date June 30, 2022 June 30, 2021
Actuarial Cost Method Entry-Age Normal Cost Method Entry-Age Normal Cost Method Actuarial Assumptions
Discount Rate 6.90% 7.15%
Inflation 2.30% 2.50%
Salary Increase Varies by entry age and service Varies by entry age and service Mortality Rate Table1 Derived using CalPERS’ membership data for all funds.

Post Retirement Benefit
Increase
The lesser of contract COLA or 2.30% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.30%
thereafter
The lesser of contract COLA or 2.50% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.50%
thereafter
1The 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 from 2001 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 the CalPERS website.

LONG-TERM EXPECTED RATE OF RETURN
The long-term expected rate of return on pension plan investments was determined using a building-block method in which expected future real rates of return (expected returns, net of pension plan investment expense and inflation) are developed for 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, expected compound (geometric) returns were calculated over the next 20 years using a building-block approach. The expected rate of return was then adjusted to account for assumed administrative expenses of 10 Basis points. The expected real rates of return by asset class are as follows:

June 30, 2022 Measurement Date
Asset Class (1)
Assumed Asset
Allocation Real Return(1),(2)
Global Equity - Cap-weighted 30.00% 4.54%
Global Equity - Non-Cap-weighted 12.00% 3.84%
Private Equity 13.00% 7.28%
Treasury 5.00% 0.27%
Mortgage-backed Securities 5.00% 0.50%
Investment Grade Corporates 10.00% 1.56%
High Yield 5.00% 2.27%
Emerging Market Debt 5.00% 2.48%
Private Debt 5.00% 3.57%
Real Assets 15.00% 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. 119
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

Post Retirement Benefit
Increase
The lesser of contract COLA or 2.30% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.30%
thereafter
The lesser of contract COLA or 2.50% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.50%
thereafter
1The 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 from 2001 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 the CalPERS website.

June 30, 2022 Measurement Date
Asset Class (1)
Assumed Asset
Allocation Real Return(1),(2)
Global Equity - Cap-weighted 30.00% 4.54%
Global Equity - Non-Cap-weighted 12.00% 3.84%
Private Equity 13.00% 7.28%
Treasury 5.00% 0.27%
Mortgage-backed Securities 5.00% 0.50%
Investment Grade Corporates 10.00% 1.56%
High Yield 5.00% 2.27%
Emerging Market Debt 5.00% 2.48%
Private Debt 5.00% 3.57%
Real Assets 15.00% 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. 119
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

Post Retirement Benefit
Increase
The lesser of contract COLA or 2.30% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.30%
thereafter
The lesser of contract COLA or 2.50% until
Purchasing Power Protection Allowance
floor on purchasing power applies, 2.50%
thereafter
1The 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 from 2001 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 the CalPERS website.

June 30, 2022 Measurement Date
Asset Class (1)
Assumed Asset
Allocation Real Return(1),(2)
Global Equity - Cap-weighted 30.00% 4.54%
Global Equity - Non-Cap-weighted 12.00% 3.84%
Private Equity 13.00% 7.28%
Treasury 5.00% 0.27%
Mortgage-backed Securities 5.00% 0.50%
Investment Grade Corporates 10.00% 1.56%
High Yield 5.00% 2.27%
Emerging Market Debt 5.00% 2.48%
Private Debt 5.00% 3.57%
Real Assets 15.00% 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. 119
NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

LONG-TERM EXPECTED RATE OF RETURN (CONTINUED)
June 30, 2021 Measurement Date
Asset Class (1)
Current Target
Allocation
Real Return
Years 1 - 10 (2)
Real Return
Years 11+ (3)
Global Equity 50.0% 4.80% 5.98%
Fixed Income 28.0% 1.00% 2.62%
Inflation Assets 0.0% 0.77% 1.81%
Private Equity 8.0% 6.30% 7.23%
Real Assets 13.0% 3.75% 4.93%
Liquidity 1.0% 0.00% -0.92%
(1) In the System's ACFR, Fixed Income is included in Global Debt Securities; Liquidity is included in Short-term Investments; Inflation Assets are included in both Global Equity Securities and Global Debt Securities. (2) An expected inflation of 2.00% used for this period. (3) An expected inflation of 2.92% used for this period.

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

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, 2023 (measurement date June 30, 2022) and 2022 (measurement date June 30, 2021) for the Plan are as follows:

June 30, 2023
Net Pension
Liability/
(Asset)
Proportion of
the Plan
Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022) $ 12,854 %9.76 Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) (8,809) %9.93 Changes - Increase / (Decrease) 21,663 %(0.17)
June 30, 2022
Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) $ (8,809) %9.93 Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 12,203 %10.16 Changes - Increase / (Decrease) (21,012) %-0.23
120
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

CHANGES IN ASSUMPTIONS
Effective with the June 30, 2021 valuation date (2022 measurement date), the accounting discount rate was reduced from

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO

PENSION
For the fiscal years ended June 30, 2023 and 2022, the Water Utility recognized pension expense/(income) of $2,373 and $(2,176), respectively. At June 30, 2023 and 2022, the Water Utility reported deferred outflows of resources and deferred inflows of resources related to pension from the following sources:

June 30, 2023 June 30, 2022
Deferred
Outflows of
Resources
Deferred
Inflows of
Resources
Deferred
Outflows of
Resources
Deferred
Inflows of
Resources
Pension contributions subsequent to
measurement date $ 2,844 $ - $ 2,715 $ -
Change of assumptions 1,321 - - -
Difference between expected and actual
expense 87 (1,187) 365 -
Net difference between projected and
actual earnings on pension plan
investments 7,336 - - (14,814)
Total $ 11,588 $ (1,187) $ 3,080 $ (14,814)
Deferred outflows of resources related to contributions subsequent to the measurement date reported in prior year was recognized as a reduction of the net pension liability in the year ended June 30, 2023.

The remaining amounts reported as deferred outflows of resources and deferred (inflows) of resources related to pensions will be recognized as pension expense as follows:

Year Ended
June 30
Deferred Outflows/
(Inflows) of
Resources
2024 $ 1,343
2025 1,151
2026 497
2027 4,566
Total $ 7,557
Subsequent Events - On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for fiscal year 2020-21. Based on the thresholds specified in CalPERS Funding Risk Mitigation policy, the excess return of 14.3% prescribes a reduction in investment 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 board elected to defer any changes to the asset allocation until the ALM process concluded, and the board could make its final decision on the asset allocation in November 2021.

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO

The remaining amounts reported as deferred outflows of resources and deferred (inflows) of resources related to pensions will be recognized as pension expense as follows:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO

The remaining amounts reported as deferred outflows of resources and deferred (inflows) of resources related to pensions will be recognized as pension expense as follows:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

SENSITIVITY OF THE NET PENSION LIABILITY (ASSET) TO CHANGES IN THE DISCOUNT RATE The following presents the Water Utility’s proportionate share of the net pension liability of the Plan, calculated using the discount rate of 6.90% (measurement date June 30, 2022), and 7.15% (measurement date June 30, 2021) as well as what the Water Utility’s proportionate share of the net pension 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 Date
June 30, 2022
Measurement Date
June 30, 2021
Discount Rate
-1%
(5.90%)
Current
Discount Rate
(6.90%)
Discount Rate
+1%
(7.90%)
Discount Rate
-1%
(6.15%)
Current
Discount Rate
(7.15%)
Discount Rate
+1%
(8.15%)
Water Utility's
proportionate share of the
Plan's net pension
liability/(asset)
$ 34,227 $ 12,854 $ (4,696) $ 11,807 $ (8,809) $ (25,787) Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports.

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB)

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 both the active and retired employees. The City is not required by law or contractual agreement to provide funding other than the pay-as-you-go amount necessary to provide current benefit to eligible retirees and beneficiaries. Retiree and spousal coverage terminates when the retiree becomes covered under another employer health plan, or when the retiree reaches Medicare eligibility age, which is currently age 65. However, retiree benefit continues to the surviving spouse if the retiree elects the CalPERS survivor annuity.

As of measurement date June 30, 2022 and 2021, the following employees, City-wide, were covered by the benefit terms:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
Discount Rate
-1%
(5.90%)
Current
Discount Rate
(6.90%)
Discount Rate
+1%
(7.90%)
Discount Rate
-1%
(6.15%)
Current
Discount Rate
(7.15%)
Discount Rate
+1%
(8.15%)
Water Utility's
proportionate share of the
Plan's net pension
liability/(asset)
$ 34,227 $ 12,854 $ (4,696) $ 11,807 $ (8,809) $ (25,787) Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports.

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB)

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 both the active and retired employees. The City is not required by law or contractual agreement to provide funding other than the pay-as-you-go amount necessary to provide current benefit to eligible retirees and beneficiaries. Retiree and spousal coverage terminates when the retiree becomes covered under another employer health plan, or when the retiree reaches Medicare eligibility age, which is currently age 65. However, retiree benefit continues to the surviving spouse if the retiree elects the CalPERS survivor annuity.

As of measurement date June 30, 2022 and 2021, the following employees, City-wide, were covered by the benefit terms:

NOTES TO THE FINANCIAL STATEMENTS

6. EMPLOYEE RETIREMENT PLAN (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
Discount Rate
-1%
(5.90%)
Current
Discount Rate
(6.90%)
Discount Rate
+1%
(7.90%)
Discount Rate
-1%
(6.15%)
Current
Discount Rate
(7.15%)
Discount Rate
+1%
(8.15%)
Water Utility's
proportionate share of the
Plan's net pension
liability/(asset)
$ 34,227 $ 12,854 $ (4,696) $ 11,807 $ (8,809) $ (25,787) Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports.

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB)

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 both the active and retired employees. The City is not required by law or contractual agreement to provide funding other than the pay-as-you-go amount necessary to provide current benefit to eligible retirees and beneficiaries. Retiree and spousal coverage terminates when the retiree becomes covered under another employer health plan, or when the retiree reaches Medicare eligibility age, which is currently age 65. However, retiree benefit continues to the surviving spouse if the retiree elects the CalPERS survivor annuity.

As of measurement date June 30, 2022 and 2021, the following employees, City-wide, were covered by the benefit terms:

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
Inactive plan members or beneficiaries
currently receiving benefits 206 206
Inactive plan members entitled to but
not yet receiving benefits - -
Active plan members 2,014 2,014
122
NOTES TO THE FINANCIAL STATEMENTS: WATER125
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

ACTUARIAL ASSUMPTIONS
The total OPEB liability was determined by actuarial valuation as of June 30, 2022 and 2021, using the following actuarial assumptions:

Miscellaneous - Current Year Miscellaneous - Prior Year Valuation Date June 30, 2021 June 30, 2021
Measurement Date June 30, 2022 June 30, 2021
Actuarial Cost Method Pay-as-you-go for implicit rate subsidy Pay-as-you-go for implicit rate subsidy Actuarial Assumptions
Discount Rate Bond Buyer 20 Index at June 30, 2022
resulting in a rate of 3.54%
Bond Buyer 20 Index at June 30, 2021
resulting in a rate of 2.16%
Inflation Rate 2.50% per annum 2.75% per annum
Payroll Increases 2.75% per year. Since benefits do not depend on salary (as they do for pensions),
this assumption is only used to determine
the accrual pattern of the Actuarial Present
Value of Projected Benefit Payments.

Mortality 2017 CalPERS Retiree Mortality Table for
the appropriated population
2017 CalPERS Retiree Mortality Table for
the appropriated population
Healthcare Trend
Rates
Medical trend in future years has been
updated to 4.00% for all years from 6.25%
tiered down by 0.25% per year to 4.50% in
all future years.

Medical trend in future years has been
updated to 4.00% for all years from 6.25%
tiered down by 0.25% per year to 4.50% in
all future years.

CHANGES OF ASSUMPTIONS
In 2022, the discount rate was changed from 2.16% to 3.54%.

SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN HEALTHCARE COST TREND RATES The following presents the Water Utility’s proportionate share of the City’s total OPEB liability, calculating using the healthcare trend rate of 4% for measurement date as of June 30, 2022 and June 30, 2021 , as well as what the Water Utility’s total OPEB liability would be if it was calculated using a healthcare cost trend rate that is 1-percentage-point lower or 1-percentage-point higher than the current rate:

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
Current
healthcare
cost trend rate
4% 1% Increase 1% Decrease
Current
healthcare
cost trend rate
4% 1% Increase
Water Utility's proportionate share of the
total OPEB liability $ 3,546 $ 4,043 $ 4,609 $ 3,771 $ 4,286 $ 4,896 123
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

ACTUARIAL ASSUMPTIONS
The total OPEB liability was determined by actuarial valuation as of June 30, 2022 and 2021, using the following actuarial assumptions:

Miscellaneous - Current Year Miscellaneous - Prior Year Valuation Date June 30, 2021 June 30, 2021
Measurement Date June 30, 2022 June 30, 2021
Actuarial Cost Method Pay-as-you-go for implicit rate subsidy Pay-as-you-go for implicit rate subsidy Actuarial Assumptions
Discount Rate Bond Buyer 20 Index at June 30, 2022
resulting in a rate of 3.54%
Bond Buyer 20 Index at June 30, 2021
resulting in a rate of 2.16%
Inflation Rate 2.50% per annum 2.75% per annum
Payroll Increases 2.75% per year. Since benefits do not depend on salary (as they do for pensions),
this assumption is only used to determine
the accrual pattern of the Actuarial Present
Value of Projected Benefit Payments.

Medical trend in future years has been
updated to 4.00% for all years from 6.25%
tiered down by 0.25% per year to 4.50% in
all future years.

CHANGES OF ASSUMPTIONS
In 2022, the discount rate was changed from 2.16% to 3.54%.

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
Current
healthcare
cost trend rate
4% 1% Increase 1% Decrease
Current
healthcare
cost trend rate
4% 1% Increase
Water Utility's proportionate share of the
total OPEB liability $ 3,546 $ 4,043 $ 4,609 $ 3,771 $ 4,286 $ 4,896 123
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

ACTUARIAL ASSUMPTIONS
The total OPEB liability was determined by actuarial valuation as of June 30, 2022 and 2021, using the following actuarial assumptions:

Miscellaneous - Current Year Miscellaneous - Prior Year Valuation Date June 30, 2021 June 30, 2021
Measurement Date June 30, 2022 June 30, 2021
Actuarial Cost Method Pay-as-you-go for implicit rate subsidy Pay-as-you-go for implicit rate subsidy Actuarial Assumptions
Discount Rate Bond Buyer 20 Index at June 30, 2022
resulting in a rate of 3.54%
Bond Buyer 20 Index at June 30, 2021
resulting in a rate of 2.16%
Inflation Rate 2.50% per annum 2.75% per annum
Payroll Increases 2.75% per year. Since benefits do not depend on salary (as they do for pensions),
this assumption is only used to determine
the accrual pattern of the Actuarial Present
Value of Projected Benefit Payments.

Medical trend in future years has been
updated to 4.00% for all years from 6.25%
tiered down by 0.25% per year to 4.50% in
all future years.

CHANGES OF ASSUMPTIONS
In 2022, the discount rate was changed from 2.16% to 3.54%.

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
Current
healthcare
cost trend rate
4% 1% Increase 1% Decrease
Current
healthcare
cost trend rate
4% 1% Increase
Water Utility's proportionate share of the
total OPEB liability $ 3,546 $ 4,043 $ 4,609 $ 3,771 $ 4,286 $ 4,896 123
NOTES TO THE FINANCIAL STATEMENTS: WATER
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN DISCOUNT RATES The following presents the Water Utility’s proportionate share of the City’s total OPEB liability, calculating using the discount rate of 3.54% and 2.16% for measurement date as of June 30, 2022 and 2021 respectively, as well as what the Water 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 Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Water Utility's
proportionate share of
total OPEB liability $ 4,432 $ 4,043 $ 3,769 $ 4,652 $ 4,286 $ 3,946

CHANGE IN TOTAL OPEB LIABILITY
For fiscal year ended June 30, 2023 and 2022, the Water Utility recognized total OPEB expense of $168 and $210 respectively. The following table shows the change in the Water Utility’s proportionate share of the City’s total OPEB liability for the year ended June 30, 2023 (measurement date June 30, 2022 ) and the year ended June 30, 2022 (measurement date June 30, 2021):

June 30, 2023
Total OPEB
Liability
Proportion of
the City
Proportion - Reporting date June 30, 2023 (Measurement Date June 30, 2022) $ 4,043 %8.89 Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) 4,286 %8.79 Changes - Increase / (Decrease) (243) %0.10
June 30, 2022
Proportion - Reporting date June 30, 2022 (Measurement Date June 30, 2021) $ 4,286 %8.79 Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 4,550 %8.70 Changes - Increase / (Decrease) (264) %0.09

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Water Utility reported deferred inflows of resources related to OPEB from the following sources:

Deferred Outflows
of Resources
Deferred Inflows of
Resources
Difference between expected and
actual expense $ 12 $ (255)
Change of assumptions 509 (634)
Contributions subsequent to
measurement date 123 -
Total $ 644 $ (889)
124
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Water Utility's
proportionate share of
total OPEB liability $ 4,432 $ 4,043 $ 3,769 $ 4,652 $ 4,286 $ 3,946

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Water Utility reported deferred inflows of resources related to OPEB from the following sources:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Water Utility's
proportionate share of
total OPEB liability $ 4,432 $ 4,043 $ 3,769 $ 4,652 $ 4,286 $ 3,946

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Water Utility reported deferred inflows of resources related to OPEB from the following sources:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Water Utility's
proportionate share of
total OPEB liability $ 4,432 $ 4,043 $ 3,769 $ 4,652 $ 4,286 $ 3,946

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Water Utility reported deferred inflows of resources related to OPEB from the following sources:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Water Utility's
proportionate share of
total OPEB liability $ 4,432 $ 4,043 $ 3,769 $ 4,652 $ 4,286 $ 3,946

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Water Utility reported deferred inflows of resources related to OPEB from the following sources:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

Measurement Date
June 30, 2022
Measurement Date
June 30, 2021
1% Decrease
(2.54%)
Current Discount
Rate
(3.54%)
1% Increase
(4.54%)
1% Decrease
(1.16%)
Current Discount
Rate
(2.16%)
1% Increase
(3.16%)
Water Utility's
proportionate share of
total OPEB liability $ 4,432 $ 4,043 $ 3,769 $ 4,652 $ 4,286 $ 3,946

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2023, the Water Utility reported deferred inflows of resources related to OPEB from the following sources:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB (CONTINUED) Amounts reported as deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:

Year Ended
June 30
Deferred Outflows/
(Inflows) of
Resources
2024 $ (10)
2025 (10)
2026 6
2027 8
2028 8
Thereafter (370)
Total $ (368)

8. RESTRICTED NET POSITION
Pursuant to applicable bond indentures, a reserve for debt service has been established by restricting assets and reserving a portion of net position. Bond indentures for the Water Utility’s water revenue and refunding bonds require debt service reserves that equate to the maximum annual debt service required in future years and bond service reserves of three months interest and nine months principal due in the next fiscal year. Variable rate revenue and refunding bonds require 110% of the monthly accrued interest to be included in the reserve. Certain issues have no debt service reserve requirements (2009B, 2011A, 2019A and 2022A).

9. CONSTRUCTION COMMITMENTS
As of June 30, 2023, the Water Utility had commitments (encumbrances) of approximately $10,834 with respect to ongoing capital projects, of which $10,077 is expected to be funded by bonds, and $757 to be funded by unrestricted reserves.

10. LITIGATION
The Water Utility is a defendant in various lawsuits arising in the normal course of business. Present lawsuits and other claims against the Water Utility are incidental to the ordinary course of operations of the Water Utility and are largely covered by the City’s self-insurance program. In the opinion of management and the City Attorney, such claims and litigation 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 of Colton and City of Rialto that is contaminated by perchlorate. The lawsuit was filed March 31, 2009. On May 24, 2018, the State trial court dismissed the action, with prejudice, for failure to join the federal Department of Defense, with instructions to refile the lawsuit in federal court and include the Department of Defense as a party. The City has appealed such dismissal, and on May 6, 2020, the appellate court overturned the trial court’s dismissal. The appellate court remanded the case back to the trial court and the parties are now waiting for the trial court to set a trial date. The City has reached settlement with two of the defendants: Trojan Fireworks Company and Zambelli and those defendants have been dismissed from the lawsuit.

PONGS V. CITY OF RIVERSIDE (“PONGS I”)
On December 16, 2019, a lawsuit entitled Pongs v. City of Riverside was filed against the City challenging the City’s Water Rate WA-12, “Agricultural Water”, alleging that the City is overcharging customers for service under this rate in violation of Article XIIID, Section 6 of the California Constitution. The plaintiff is seeking that the court invalidate Water Rate WA-12 and refund all to all WA-12 customers monies collected under that rate. A hearing date for the first phase of the trial, on liability, has been scheduled for November 17, 2021. This lawsuit has been stayed pending the resolution of another lawsuit challenging the City’s Water General Fund Transfer, entitled Simpson v. City of Riverside (as referenced below). 125
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB (CONTINUED) Amounts reported as deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:

Year Ended
June 30
Deferred Outflows/
(Inflows) of
Resources
2024 $ (10)
2025 (10)
2026 6
2027 8
2028 8
Thereafter (370)
Total $ (368)

CITY OF RIVERSIDE V. BLACK & DECKER (U.S.), INC.

NOTES TO THE FINANCIAL STATEMENTS

7. OTHER POST-EMPLOYMENT BENEFITS (OPEB) (CONTINUED)

DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB (CONTINUED) Amounts reported as deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:

Year Ended
June 30
Deferred Outflows/
(Inflows) of
Resources
2024 $ (10)
2025 (10)
2026 6
2027 8
2028 8
Thereafter (370)
Total $ (368)

CITY OF RIVERSIDE V. BLACK & DECKER (U.S.), INC.

NOTES TO THE FINANCIAL STATEMENTS

10. LITIGATION (CONTINUED)
SIMPSON V. CITY OF RIVERSIDE
On December 19, 2019, a class action lawsuit entitled Simpson v. City of Riverside was filed against the City alleging that the City is overcharging customers for water utility service in violation of Article XIIID, Section 6 of the California Constitution, on the grounds that the City is transferring 11.5% of water utility revenues to the City’s general fund. The transfer, also known as the “General Fund Transfer”, was approved by voters on June 4, 2013, as a general tax. The plaintiff is seeking refunds for all customers for monies collected in violation and also that the court set aside the voter’s 2013 approval of the General Fund Transfer. The trial was bifurcated into two phases, liability and damages. The Court issued its ruling on the liability phase on August 17, 2023, finding that the City’s water rates violated Article XIID, Section 6 of the California Constitution because they were set in an amount sufficient to recover the General Fund Transfer. A trial date of April 3, 2024 has been set for the second phase of the trial regarding damages.

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 synthetic per- and polyfluoroalkyl substances (“PFAS”). The lawsuit was filed July 26, 2021 as part of a multidistrict litigation proceeding 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 date has been set.

PONGS ET AL. V. CITY OF RIVERSIDE ET AL. (“PONGS III”)
On December 22, 2022, a lawsuit entitled Pongs et al. v. City of Riverside et al. was filed against the City by two water customers challenging the City’s issuance of water revenue bonds, alleging that the issuance of the bonds violated Proposition 218 because the City had agreed to fix and raise rates to pay for the costs of debt service on the bonds and the bonds improperly required water customers to pay for pension liabilities of retired City employees. The trial was conducted on August 18, 2023. The Court ruled in favor of the City on all causes of action. To date, no appeal has been filed.

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, was filed against the City by a water customer as an individual and seeking class action certification, alleging that the City improperly acquired shares in the Gage Canal Company in breach of the Gage Canal Operating Agreement entered into on June 9, 1965. Plaintiff seeks return of the Gage Canal shares to all shareholders improperly divested of shares and that the Court enjoin the City from continuing its current practice to acquire ownership of Gage Canal shares. No trial date has been set in this matter. 126
NOTES TO THE FINANCIAL STATEMENTS: WATER129
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS For the year ended June 30, 2022, the financial statements included the adoption of GASB Statement No. 87, Leases. The primary objective of this statement is to enhance the relevance and consistency of information about governments' leasing activities. This statement establishes a single model for lease accounting based on the principle that leases are financings of the right to use an underlying asset. Under this statement, a lessee is required to recognize a lease liability and a lease asset, and a lessor is required to recognize a lease receivable and a deferred inflow of resources. For additional information, refer to the disclosures below.

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 that conveys control of the right to use another party’s information technology software, alone or in a combination with tangible capital asset, as specified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer to the disclosures below.

LEASES PAYABLE
The Water Utility has 4 leases as Lessee for the use of various pieces of machinery and equipment as of the end of the fiscal year. The Water Utility is required to make principal and interest payments through fiscal year 2026. An initial lease liability was recorded in the amount of $25. As of June 30, 2023, the value of the lease liability is $14. The leases have an interest rate of 0.52%. The value of the lease asset as of June 30, 2023 is $21 with accumulated amortization of $10 and is included with machinery and equipment on the Asset Class activities table found below.

Amount of Lease Assets by
Major Classes of
Underlying Asset
Asset Class
Lease Asset
Value
Accumulated
Amortization
Machinery and equipment $ 21 $ (10)
Total $ 21 $ (10)
Fiscal Year
Principal
Payments
Interest
Payments
Total
Payments
2024 $ 5 $ - $ 5
2025 4 - 4
2026 3 - 3
Total $ 12 $ - $ 12
127
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

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 that conveys control of the right to use another party’s information technology software, alone or in a combination with tangible capital asset, as specified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer to the disclosures below.

NOTES TO THE FINANCIAL STATEMENTS

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 that conveys control of the right to use another party’s information technology software, alone or in a combination with tangible capital asset, as specified in a contract for a period of time in an exchange or exchange-like transaction. For additional information, refer to the disclosures below.

NOTES TO THE FINANCIAL STATEMENTS

11. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

LEASES RECEIVABLE
The Water Utility has 22 leases as a Lessor for the use of various pieces of land and building as of the end of the fiscal year. The terms range from 2 to 110 years beginning on the contract commencement date. An initial lease receivable was recorded in the amount of $83,950. As of June 30, 2023, the value of the lease receivable is $85,386. The leases have interest rates ranging from 0.52% to 2.81%. The value of the deferred inflow of resources as of June 30, 2023 was $84,102, and the Water Utility recognized lease revenue of $1,708 during the fiscal year.

Fiscal Year
Principal
Payments
Interest
Payments
Total
Payments
2024 $ 1,001 $ 1,531 $ 2,532
2025 1,027 1,507 2,534
2026 1,046 1,486 2,532
2027 745 1,466 2,211
2028 469 1,460 1,929
2029-2033 2,286 7,157 9,443
2034-2038 2,259 6,957 9,216
2039-2043 2,342 6,753 9,095
2044-2048 2,824 6,525 9,349
2049-2053 3,407 6,243 9,650
2054-2058 4,089 5,908 9,997
2059-2063 4,803 5,508 10,311
2064-2068 5,204 5,052 10,256
2069-2073 2,855 4,698 7,553
2074-2078 3,046 4,433 7,479
2079-2083 3,331 4,148 7,479
2084-2088 3,641 3,838 7,479
2089-2093 3,984 3,494 7,478
2094-2098 4,356 3,121 7,477
2099-2103 4,766 2,711 7,477
2104-2108 5,209 2,267 7,476
2109-2113 5,698 1,777 7,475
2114-2118 6,232 1,243 7,475
2119-2123 6,815 659 7,474
2124-2128 3,951 118 4,069
Total $ 85,386 $ 90,060 $ 175,446

SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS PAYABLE The Water Utility has 2 subscription-based information technology arrangements (SBITA) for the use of various software as of the end of the fiscal year. The Water Utility is required to make principal and interest payments through fiscal year 2025. An initial lease liability was recorded in the amount of $32. As of June 30, 2023, the value of the subscription liability was $17. The subscriptions have interest rate of 0.52%. The value of the subscription asset as of June 30, 2023 of $32 with accumulated amortization of $15.

Fiscal Year Principal Interest
Total
Payments
2024 $ 15 $ - $ 15
2025 2 - 2
Total $ 17 $ - $ 17
128
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

Fiscal Year Principal Interest
Total
Payments
2024 $ 15 $ - $ 15
2025 2 - 2
Total $ 17 $ - $ 17
128
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

Fiscal Year Principal Interest
Total
Payments
2024 $ 15 $ - $ 15
2025 2 - 2
Total $ 17 $ - $ 17
128
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

Fiscal Year Principal Interest
Total
Payments
2024 $ 15 $ - $ 15
2025 2 - 2
Total $ 17 $ - $ 17
128
WATER UTILITY:

NOTES TO THE FINANCIAL STATEMENTS

11. LEASES AND SUBSCRIPTION-BASED INFORMATION TECHNOLOGY ARRANGEMENTS (CONTINUED)

Fiscal Year Principal Interest
Total
Payments
2024 $ 15 $ - $ 15
2025 2 - 2
Total $ 17 $ - $ 17
128
NOTES TO THE FINANCIAL STATEMENTS: WATER131

WATER UTILITY

KEY HISTORICAL OPERATING DATA
Fiscal Year 2022/23 2021/22 2020/21 2019/20 2018/19

WATER SUPPLY (ACRE FEET)
Potable water production1 60,185 68,054 72,215 64,827 64,379 Percentage pumped (%)2 100 100 100 100 100
System peak day (gallons)3 81,800,000 82,700,000 91,900,000 89,600,000 90,200,000

WATER USE
Number of meters as of year end:

Residential 59,907 59,876 59,782 59,598 59,456
Commercial/Industrial 6,175 6,153 6,080 6,068 6,028
Other 359 343 336 365 319
Total 66,441 66,372 66,198 66,031 65,803
CCF* sales:

Residential 13,078,242 15,362,908 16,149,357 14,610,481 14,157,606 Commercial/industrial4 9,003,457 10,245,377 10,069,176 9,126,132 9,191,682 Other4 764,265 870,928 835,300 787,119 805,022
Subtotal 22,845,964 26,479,213 27,053,833 24,523,732 24,154,310 Wholesale 821,502 366,370 1,571,549 1,002,289 1,673,411 Total 23,667,466 26,845,583 28,625,382 25,526,021 25,827,721 *(CCF equals 100 cubic feet)

WATER FACTS
Average annual CCF
per residential customer 218 257 270 245 238
Average price ($/CCF)
per residential customer $ 3.38 $ 2.98 $ 2.77 $ 2.67 $ 2.50 Debt service coverage ratio (DSC)5, 6, 7, 8 1.93 2.23 2.25 1.80 1.68 Employees9 165 164 165 165 159
1 Water pumping figures have been adjusted to include retail and wholesale potable water production. 2 No purchased water.
3 System peak day has been adjusted to reflect production for retail customers. 4 Changes in fiscal years 18/19 & 19/20 reflect reclassification of certain Commercial/Industrial accounts and Other accounts in connection with current Water Rate 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 ($471), ($4,891), ($1,107), $1,046, and ($482) for fiscal years 22/23 through FY18/19, respectively.
7 Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of 168, $210, $73, $197, and $118, for fiscal years 22/23 through FY 18/19, respectively. 8 Includes GASB 87 Leases net revenue adjustments of $728 and $708 for fiscal years 22/23 and 21/22, respectively. 9 Approved positions.
129
KEY HISTORICAL OPERATING DATA: WATER

SOURCE OF

REVENUE
Residential Sales 51¢
Commercial Sales 27¢
Other Revenue 15¢
Investment Income 4¢
Other Sales 3%

DISTRIBUTION OF

REVENUE
Operations and Maintenance 57¢
Debt Service 21¢
Transfers to the City's General Fund* 9¢
Additions & Replacements to the System 8¢
Additional Reserves 4¢
Water Conservation 1¢

WATER RESOURCES
San Bernardino Basin Wells 66%
Riverside Basin Wells 34%
Purchased Water 0%
Western MWD
Eastern MWD
Riverside
Public
Utilities
$0
$20
$40
$60
$80
$100
$120
83% Higher 74% Higher $58
*Based on transfer of 11.5% of fiscal year
2021/2022 gross operating revenues,
including adjustments
$106 $101 130
KEY HISTORICAL OPERATING DATA: WATER133

65,803
66,031
66,198
66,372
66,441
2019
2020
2021
2022
2023
Number of Meters At Year End
$65.1
$69.7
$80.3
$80.1
$78.7
2019
2020
2021
2022
2023
Total Operating Revenue (In Millions)
64,379
64,827
72,215
68,054
60,185
2019
2020
2021
2022
2023
Potable Water Production (In Acre Feet)

90.2 89.6

91.9 82.7

81.8 2019
2020
2021
2022
2023
Peak Day Demand (In Millions of Gallons)
$6.6
$6.5
$7.0
$7.7
$8.2
2019
2020
2021
2022
2023
General Fund Transfer (In Millions)
131
KEY HISTORICAL OPERATING DATA: WATER

WATER FACTS AND SYSTEM DATA
Established................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................1913 Service Area Population................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................313,676 Service Area Size (square miles)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................74.24 System Data:

Smallest Pipeline................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................2.0" Largest Pipeline................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................72.0" Miles of Pipeline................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................993 Number of Domestic Wells................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................53 Number of Active Reservoirs................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................16 Total Reservoir Capacity (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................108,500,000 Number of Treatment Plants................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................6 Number of Treatment Vessels................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................84 Miles of Canal................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................14 Number of Fire Hydrants................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................8,023 Daily Average Production (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................57,600,000 2022-2023 Peak Day (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................81,800,000 07/18/22, 101 Degrees
Historical Peak (gallons)................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................118,782,000 08/9/05, 99 Degrees
Bond Ratings:

Fitch Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA+ Moody's................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................Aa2 S&P Global Ratings................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................AA+ 132
KEY HISTORICAL OPERATING DATA: WATER135

RIVERSIDE PUBLIC UTILITIES
3750 University Avenue, 5th Floor
Riverside, CA 92501
(951) 826-2135
RiversidePublicUtilities.com

Financial Performance and Budget CommitteeJanuary 10, 2024

Financial Performance and Budget Committee
January 10, 2024