2021
FINANCIAL
REPORT
RIVERSIDE PUBLIC UTILITIES
RiversidePublicUtilities.com
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.
SERVICE AREA POPULATION
324,243
RECORD PEAK DEMAND
Energy:
Water:
TOTAL OPERATING REVENUE
Energy:
Water:
CUSTOMERS
Energy:
Water:
CREDIT RATING
Energy:
Water:
AA- Fitch
AA- S&P Global
AA+ Fitch
AAA S&P Global
Aa2 Moody’s
640 megawatts
8/31/2017
365 acre feet
119 million gallons
8/9/2005
$372.1 million
$80.3 million
111,711
66,198
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
Elizabeth Sanchez-Monville
(Board Chair)
Ward 3
David M. Crohn
(Board Vice Chair)
Ward 1
Ana S. Miramontes
Ward 2
Gary Montgomery
Ward 4
Nancy E. Melendez
Ward 5
Rosemary Heru
Ward 6
Gil Oceguera
Ward 7
Peter Wohlgemuth
Citywide / Ward 1
Deborah S. Cherney
Citywide/Ward 4
EXECUTIVE MANAGEMENT
Al Zelinka
City Manager
Todd Corbin
Utilities General Manager
Daniel E. Garcia
Utilities Deputy General Manager
George Hanson
Utilities Assistant General Manager
Energy Delivery
Todd Jorgenson
Utilities Assistant General Manager
Water Delivery
Carlie Myers
Utilities Assistant General Manager
Business Systems and
Customer Service
TABLE OF CONTENTS
Overview and Vision
Envision Riverside 2025
Executive Management, City Council and Board of Public Utilities
OUR ELECTRIC
Independent Auditors’ Report
Management’s Discussion and Analysis
Financial Statements
Statements of Net Position
Statements of Revenues, Expenses and Changes in Net Position Statements of Cash Flows
Notes to the Financial Statements
Supplementary Electric Information
Key Historical Operating Data
OUR WATER
Independent Auditors’ Report
Management’s Discussion and Analysis
Financial Statements
Statements of Net Position
Statements of Revenues, Expenses and Changes in Net Position Statements of Cash Flows
Notes to the Financial Statements
Supplementary Water Information
Key Historical Operating Data
9 12
31 33
34 35
74 81
84 96
98 99
100
129
ELECTRICOUR
RIVERSIDE PUBLIC UTILITIES
INDEPENDENT AUDITORS’ REPORT
To the Honorable City Council and Board of Public Utilities City of Riverside, California
Report on the Financial Statements
Opinions
We have audited the accompanying financial statements of the El ectric Utility Enterprise Fund (Electric Utility) of the City of Riverside, California, (the City) as of and for the years ended June 30, 2021 and 2020, and the related notes to the financial statements, which collectively comprise the Electric Utility’s financial statements as listed in the table of contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Electric Utility Enterprise Fund of the City of Riverside, as of June 30, 2021 and 2020, and the respective changes in financial position and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matters
As discussed in Note 1, the financial statements present only the Electric Utility Enterprise Fund of the City of Riverside and do not purport to, and do not present fairly t he financial position of the City as of June 30, 2021 and 2020, the changes in its financial position, or, where applicable, its cash flows for the years then ended in accordance with accounting principles gener ally accepted in the United States of America. Our opinion is not modified with respect to this matter.
Basis for Opinions
We conducted our audit in accordance with auditing standards ge nerally accepted in the United States of America (GAAS) and the standards applicable to financial aud its contained in Government Auditing Standards, issued by the Comptroller General of the United States. Our r esponsibilities under those standards are further described in the Auditor’s Responsibiliti es for the Audit of the Financial Statements section of our report. We are required to be independent of the Electric Utility and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presenta tion of these financial statements in accordance with accounting prin ciples generally accepted in the United States of America; and for the design, implementation, and maintenance of internal control rel evant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial dou bt about the Electric Utility’s ability to continue as a going concern for twelve months beyond the date of the financial statements.
203 N. Brea Blvd., Suite 203
Brea, CA 92821 Lance, Soll & Lunghard, LLP Phone: 714.672.0022
To the Honorable City Council and Board of Public Utilities City of Riverside, California
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with t he GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusi on, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users made on the basis of these financial statements. In performing an audit in accordance with GAAS, we:
Exercise professional judgment and maintain professional skept icism throughout the audit. Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures respons ible to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
Obtain an understanding of internal control relevant to the au dit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Electric Utility’s internal control. Accordingly, no such opinion is expressed. Evaluate the appropriateness of accounting policies used and t he reasonableness of significant accounting estimates made by management, as well as evaluate th e overall presentation of the financial statements.
Conclude whether, in our judgment, there are conditions or eve nts, considered in the aggregate, that raise substantial doubt about the Electric Utility’s abili ty to continue as a going concern for a reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
Other Reporting Responsibilities
Required Supplementary Information
Accounting principles generally accepted in the United States o f America require that the management’s discussion and analysis as listed in the table of content, be p resented to supplement the basic financial statements. Such information is the responsibility of managemen t and, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board, who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied c ertain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about th e methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements.
We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
To the Honorable City Council and Board of Public Utilities City of Riverside, California
Other Information
Our audit was conducted for the purpose of forming opinions on the financial statements of the Electric Utility’s financial statements. The key historical ope rating data are presented for purposes of additional analysis and are not a required part of the basic financial statements.
The key historical operating data have not been subjected to th e auditing procedures applied in the audit of the basic financial statements and, accordingly, we do not express an opinion or provide any assurance on them.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards , we have also issued our report dated November 9, 2021 on our consideration of the City’s internal co ntrol over financial reporting and on our tests of its compliance with certain provisions of laws, regula tions, contracts, and grant agreements and other matters. The purpose of t hat report is solely to describe the scope of our testing of Internal control over financial reporting and compliance and th e results of that testing, and not to provide an opinion on the effectiveness of the City’s internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards in considering the City’s internal control over financial reporting and compliance.
Brea, California
November 9, 2021
Retail sales, net of uncollectibles/recovery were $318,373 and $308,823 for years ended June 30, 2021 and 2020, respectively. The increase in sales was primarily due to an increase in residential sales and rate plan increases, offset by a decrease in commercial and industrial sales along with increased uncollectibles.
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 $9,682 and $3,364 in June 30, 2021 and 2020, respectively. Operating expense reflects a non-cash other post-employment benefit (OPEB) other than pension accounting standard adjustment, which will continue to fluctuate yearly. The adjustment was $183 and $490 in June 30, 2021 and 2020, respectively.
Utility plant assets as of June 30, 2021 increased by $7,404 primarily due to an increase in additions and improvements to the Electric distribution infrastructure system to improve service and reliability to Electric Utility’s customers, offset by current year depreciation. Investment income for the year ended June 30, 2021 decreased by $13,536 due to a fair market value adjustment of investments and a lower overall interest rate in the current fiscal year. Total net position as of June 30, 2021 decreased by $17,512 primarily due to a reduction in investment income and a decrease of $4,433 in capital contributions.
OO VV EE RRVV IIEE WW OOFF TT HH EE FF II NNAA NN CC IIAA LL SS TTAA TT EEMM EENN TT SS 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.”
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.
EELLEECCTTRRIICC UUTTIILLIITTYY::
MMAANNAAGGEEMMEENNTT’’SS DDIISSCCUUSSSSIIOONN AANNDD AANNAALLYYSSIISS 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 2020-21 financial report for the periods ended June 30, 2021 and 2020 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 31 of this report. All amounts, unless otherwise indicated, are expressed in thousands of dollars.
FF IINN AA NN CCII AA LL HH II GGHH LL II GGHH TT SS MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
OO VV EE RRVV IIEE WW OOFF TT HH EE FF II NNAA NN CC IIAA LL SS TTAA TT EEMM EENN TT SS (( CCOO NN TT IINN UU EEDD )) 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 73 of this report.
CC OO RROO NNAA VVII RRUU SS DD IISS EEAA SS EE 22 00 1199 (( CCOO VV IIDD -- 11 99)) In December 2019, an outbreak of a novel strain of coronavirus (COVID-19) spread to a number of countries, including the United States (U.S.). On March 11, 2020, the World Health Organization characterized COVID-19 as a pandemic. In addition, several states in the U.S., including California, declared a state of emergency. Potential impacts to the City future tax revenues include disruptions or restrictions on current employees’ ability to work. Any of the foregoing could negatively impact revenues and the City currently cannot anticipate all of the ways in which this health epidemic, COVID-19, could adversely impact our government agency. Potential impacts will continue to be monitored.
C O R O N A V I R U S A I D , R E L I E F , A N D E C O N O M I C S E C U R I T Y A C T ( C A R E S ) On March 27, 2020, President Trump signed the Coronavirus Aid, Relief, and Economic Security Act into law to provide emergency appropriations during the Coronavirus pandemic. The CARES Act represented the third package of assistance from the federal government, providing $2.2 trillion in economic relief to individuals, families, businesses, and nonprofit organizations. Funding for governments was also included through the creation of the Coronavirus Relief Fund, which allocated $150 billion to various State, local and Tribal governments. The Coronavirus Relief Fund (CRF) was distributed to State, local and Tribal governments based on relative population. Local governments with a population of 500,000 or more were eligible to receive a direct allocation from the CRF. Given the population threshold, the City was not eligible to receive a direct allocation.
Throughout the COVID-19 pandemic, the Big City Mayors (BCM) met with federal and state elected officials to advocate for much needed assistance. As part of this effort, the BCM engaged the State’s legislative leaders and Governor to solicit support for the creation of a dedicated funding opportunity for the seven cities (Long Beach, Oakland, Bakersfield, Anaheim, Santa Ana, Riverside, and Stockton) of the coalition that did not receive a direct allocation from the CRF due to population size. This targeted advocacy effort resulted in the inclusion of a specific $225 million set-aside for these seven cities as part of the State budget with the City of Riverside receiving an allocation of approximately $28 million. The CARES Act spending plan was approved by City Council on August 4, 2020 and on July 13, 2021, a final CARES Act expenditure report was presented to City Council.
A M E R I C A N R E S C U E P L A N A C T ( A R P A )
On March 11, 2021, President Biden passed the $1.9 trillion American Rescue Plan Act (ARPA) that is sending checks to families and offering small business support to drive up demand and counter the country’s high unemployment. The ARPA established Coronavirus State Fiscal Recovery Fund and Coronavirus Local Fiscal Recovery Fund, which provides a combined $350 billion in assistance to eligible state, local, territorial, and Tribal governments to assist in the economic and health recovery by providing resources to address impacts resulting from the crisis. The City will receive one-time fund of approximately $73.5 million from ARPA with the first installment of $36.7 million received in June 2021 and the remainder will be received in June 2022.
MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
13 As of 2021 City and the Electric Utility are continuing to monitor and assess the effects of the COVID-19 pandemic on our government agency and the public. The City and the Electric Utility are pursuing all available programs to assists with impacts of the pandemic. For additional information, refer to the ACFR.
EE LLEE CCTT RRII CC UU TTII LL IITT YY FF II NNAA NN CCIIAA LL AA NN AA LL YYSS IISS
CONDENSED STATEMENTS OF NET POSITION
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
2021 compared to 2020 The Electric Utility’s total assets and deferred outflows of resources were $1,324,319, reflecting a decrease of $107,000 (7.5%), primarily due to the following:
Current and other assets, comprised of restricted and unrestricted assets, had a net decrease of $40,303, primarily due to the use of $25,217 in restricted bond proceeds to fund capital projects, and a decrease of $12,440 in unrestricted cash and cash equivalents primarily due to COVID-19 impacts.
The net decrease was offset by an increase of $1,295 in restricted cash and cash equivalents, and an increase of $1,934 in accounts receivable primarily due to COVID-19 impacts. Capital assets increased by $7,404 primarily due to an increase of $41,701 in additions and improvements to the Electric distribution infrastructure system to improve service and reliability to Electric Utility’s customers, offset by $34,299 in current year depreciation. Additional capital asset information can be found in the “Capital Assets and Debt Administration” section. Deferred outflows of resources decreased by $74,101 primarily due to the payment outflow of the 2020 Pension Obligation Bond Series A, of which, the Electric Utility’s portion is $66,119. Additionally, there was a decrease 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. 2020 compared to 2019 Total assets and deferred outflows of resources were $1,431,319, a net increase of $64,357 (4.7%). Current and other assets had a net decrease of $1,649, primarily due to the use of $23,827 in restricted bond proceeds to fund capital projects. The net decrease was offset by an increase 2021 2020 2019
Current and other assets 483,635$ 523,938$ 525,587$ Capital assets 797,902 790,498 794,712
Deferred outflows of resources 42,782 116,883 46,663 Total assets and deferred outflows of resources 1,324,319 1,431,319 1,366,962 Long-term debt outstanding 639,791 662,290 616,130 Other liabilities 184,848 244,662 224,007 Deferred inflows of resources 2,307 9,482 16,093 Total liabilities and deferred inflows of resources 826,946 916,434 856,230 Net investment in capital assets 237,968 238,847 255,893 Restricted 57,884 54,615 47,876
Unrestricted 201,521 221,423 206,963
Total net position 497,373$ 514,885$ 510,732$ CC OO RROO NNAA VVII RRUU SS DD IISS EEAA SS EE 22 00 1199 (( CCOO VVII DD-- 11 99)) (( CCOO NNTT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
of $6,285 in unrestricted cash and cash equivalents, an increase of $7,786 in restricted cash and cash equivalents, an increase of $10,629 in accounts receivable, and favorable operating results. Capital assets decreased by $4,214 primarily due to $30,385 current year depreciation, offset by an increase of $26,507 in additions and improvements to the Electric distribution infrastructure system to improve service and reliability to the Electric Utility’s customers. Deferred outflows of resources increased by $70,220 primarily due to the issuance of the 2020 Pension Obligation Bond Series A, of which, the Electric Utility’s portion is $66,119. Additionally, there was an increase in the fair market value of interest rate swaps.
LIABILITIES AND DEFERRED INFLOWS OF RESOURCES
2021 compared to 2020 The Electric Utility’s total liabilities and deferred inflows of resources were $826,946, a decrease of $89,488 (9.8%), due to the following:
Long-term debt outstanding decreased by $22,499 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 decreased by $59,814 primarily due to a decrease of $50,559 in net pension liability, and a decrease of $7,483 due to a decrease in the fair market value of interest rate swaps. Deferred inflows of resources decreased by $7,175 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.
2020 compared to 2019 Total liabilities and deferred inflows of resources were $916,434, an increase of $60,204 (7.0%). Long-term debt outstanding increased by $46,160 primarily due to the issuance of the 2020 Pension Obligation Bond Series A, offset by a decrease in revenue bonds payable and leases payable. Other liabilities increased by $20,655 primarily due to an increase of $5,324 in net pension liability, an increase of $8,414 due to an increase in the fair market value of interest rate swaps, and an increase of $5,717 in the current portion due of long-term bond payables. Deferred inflows of resources decreased by $6,611 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.
NET POSITION
2021 compared to 2020 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 $497,373, a decrease of $17,512 (3.4%). The following represents the changes in components of Net Position:
The largest portion of the Electric Utility’s total net position, $237,968 (47.9%), reflects its investment in capital assets less any related outstanding debt used to acquire those assets. Additional capital asset information can be found in the “Capital Assets and Debt Administration” section. The restricted portion of net position totaled $57,884 (11.6%), an increase of $3,269, 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 $201,521 (40.5%), a decrease of $19,902 from prior year, which is primarily attributable to a reduction of $13,536 in investment income and $4,433 in capital contributions. Unrestricted net position may be used to meet the Electric Utility’s ongoing operational needs and obligations to customers and creditors.
EE LLEE CCTT RRII CC UU TTII LL IITT YY FF II NNAA NN CCIIAA LL AA NN AA LLYYSS IISS (( CC OONN TTII NN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
15 2020 compared to 2019 Total net position, increased by $4,153 (0.8%), to a total of $514,885. Net investment in capital assets decreased by $17,046 primarily due to an increase in long-term debt, the current portion of long-term debt, and a decrease in utility plant. Restricted net position increased by $6,696, and the unrestricted portion increased by $14,503 primarily attributable to the use of bond proceeds to fund capital projects, positive operating results, and a reimbursement from Southern California Edison related to the Riverside Transmission Reliability Project.
CONDENSED STATEMENTS OF CHANGES IN NET POSITION
2021 2020 2019
Revenues:
Retail sales, net 318,373$ 308,823$ 304,172$ Wholesale sales 27 - 344 Transmission revenues 32,316 34,817 35,730 Investment income 496 14,032 13,372 Other revenues 18,995 15,845 17,397 Public Benefit Programs 9,252 9,478 9,292 Capital contributions 5,059 9,492 6,383 Total revenues 384,518 392,487 386,690 Expenses:
Production and purchased power 163,908 157,540 155,264 Transmission 59,770 58,830 64,443 Distribution 70,479 64,546 58,729 Public Benefit Programs 6,419 6,440 8,933 Depreciation 35,654 35,151 34,471 Interest expenses and fiscal charges 25,901 26,269 25,053 Total expenses 362,131 348,776 346,893 Transfers to the City's general fund (39,899) (39,558) (39,886) Changes in net position (17,512) 4,153 (89) Net position, July 1, as previously reported 514,885 510,732 505,412 Less: Cumulative effect of change in accounting principle (1) - - 5,409 Net position, July 1, as restated 514,885 510,732 510,821 Net position, June 30 497,373$ 514,885$ 510,732$ (1) For the restatement of pension allocation, GASB Statement No. 68, for the year ended June 30, 2019.
EE LLEE CCTT RRII CC UU TTII LL IITT YY FF II NNAA NN CCIIAA LL AA NN AA LLYYSS IISS (( CC OONN TTII NN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
REVENUES BY SOURCES
2021 compared to 2020 The Electric Utility’s total revenues of $384,518 decreased by $7,969 (2.0%) with changes in the following:
Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $318,373, a $9,550 (3.1%) increase. Retail sales continue to be the primary revenue source for the Electric Utility. The increase in sales was primarily due to an increase in residential sales and rate plan increases, offset by a decrease in commercial and industrial sales along with increased uncollectibles. Transmission revenues of $32,316 decreased by $2,501 (7.2%), primarily due to a decrease of $1.35 per megawatt hour in the average Transmission Revenue Requirement rate. Investment income of $496 decreased by $13,536 (96.5%) due to a fair market value adjustment of investments and a lower overall interest rate in the current fiscal year. Other revenues of $18,995 increased by $3,150 (19.9%), primarily due to the sale of nuclear fuel and related decommissioning expenses.
Capital contributions of $5,059 decreased by $4,433 (46.7%), mainly due to a decrease in donated underground electrical conduit.
2020 compared to 2019 The Electric Utility’s total revenues of $392,487 increased by $5,797 (1.5%) with changes in the following:
Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $308,823, a $4,651 (1.5%) increase. Retail sales continue to be the primary revenue source for the June 30, 2021
Retail Sales 83%
Transmission Revenues 8%
Other 5%
Public Benefit Programs 2%
Investment Income 1%
Capital Contributions 1%
Wholesale Sales <1%
June 30, 2020
Retail Sales 79%
Transmission Revenues 9%
Other 4%
Public Benefit Programs 2%
Investment Income 4%
Capital Contributions 2%
Wholesale Sales <1%
EE LLEE CCTT RRII CC UU TTII LL IITT YY FF II NNAA NN CCIIAA LL AA NN AA LL YYSS IISS (( CCOO NN TT II NNUU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
17 Electric Utility. The increase in sales was primarily due to an increase in residential sales and rate plan increases, offset by a decrease in commercial and industrial sales. Transmission revenues of $34,817 decreased by $913 (2.6%), primarily due to a slight decrease in the load requirements and a decrease in the average Transmission Revenue Requirement rate of $0.32 per megawatt hour.
Investment income of $14,032 increased by $660 (4.9%) due to a higher overall interest rate in the current fiscal year.
Other revenues of $15,845 decreased by $1,552 (8.9%), primarily due to a write-off for the bankruptcy filing of Ice Energy Holdings, Inc., as well as a decrease in SONGS settlement recoveries.
EXPENSES BY SOURCES
2021 compared to 2020 The Electric Utility’s total expenses, excluding general fund transfer, were $362,131, an increase of $13,355 (3.8%). The increase was primarily due to the following:
Production and purchased power expenses of $163,908 increased by $6,368 (4.0%) primarily due to an increase in the cost of energy.
Transmission expenses of $59,770 increased by $940 (1.6%), mainly due to an increase in maintenance costs related to the Southern Transmission System. Distribution expenses of $70,479 increased by $5,933 (9.2%), mainly due to a non-cash pension adjustment of $9,682 compared to prior year non-cash pension adjustment of $3,364 as a result of pension accounting standards.
June 30, 2021
Production 40%
Distribution 17%
Transmission 15%
Contribution to the City's General Fund 11%
Depreciation 9%
Interest Expense 6%
Public Benefit Programs 2%
June 30, 2020
Production 40%
Distribution 16%
Transmission 15%
Contribution to the City's General Fund 11%
Depreciation 9%
Interest Expense 7%
Public Benefit Programs 2%
EE LLEE CCTT RRII CC UU TTII LL IITT YY FF II NNAA NN CCIIAA LL AA NN AA LL YYSS IISS (( CCOO NN TT II NNUU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
Depreciation expense of $35,654 increased by $503 (1.4%), reflecting the completion of capital projects and their current year depreciation.
2020 compared to 2019 The Electric Utility’s total expenses, excluding general fund transfer, were $348,776, an increase of $1,883 (0.5%). The increase was primarily due to the following:
Production and purchased power expenses of $157,540 increased by $2,276 (1.5%) primarily due to an increase in resource adequacy capacity purchases.
Transmission expenses of $58,830 decreased by $5,613 (8.7%), mainly due to an unanticipated decrease in maintenance costs related to the Southern Transmission System and a decrease in Southern California Edison’s high voltage rate for firm transmission. Distribution expenses of $64,546 increased by $5,817 (9.9%), mainly due to a non-cash pension credit adjustment of $3,364 compared to prior year non-cash pension adjustment of ($1,323) as a result of pension accounting standards.
Depreciation expense of $35,151 increased by $680 (2.0%), reflecting the completion of capital projects and their current year depreciation.
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 $39,899 and $39,558 for 2021 and 2020, respectively based on the gross operating revenue provisions in the City’s Charter. Additional information can be found in Note 13 of the accompanying financial statements.
CC AA PP II TTAA LL AA SS SS EETT SS AA NN DD DD EEBB TT AA DD MMII NN II SSTT RR AA TTII OO NN
CAPITAL ASSETS
The Electric Utility’s investment in capital assets includes investments in production, transmission, and distribution related facilities, land, intangibles, construction in progress, as well as general items such as office equipment, furniture, etc.
The following table summarizes the Electric Utility’s capital assets, net of accumulated depreciation, at June 30:
2021 2020 2019
Production 157,370$ 165,198$ 170,209$ Transmission 27,678 24,569 25,440 Distribution 404,352 396,498 389,552 General 63,689 64,505 67,250 Intangibles 8,639 11,077 13,274 Land 53,042 53,032 53,029 Intangibles, non-amortizable 10,651 10,651 10,651 Construction in progress 72,481 64,968 65,307 Total capital assets 797,902$ 790,498$ 794,712$
EE LLEE CCTT RRII CC UU TTII LL IITT YY FF II NNAA NN CCIIAA LL AA NN AA LL YYSS IISS (( CCOO NN TT II NNUU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
19 2021 compared to 2020 The Electric Utility’s investment in capital assets, net of accumulated depreciation, was $797,902, an increase of $7,404 (0.9%). The increase resulted primarily from the following significant capital projects offset by current year depreciation:
$18,362 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 for additional generation import capability for a second point of interconnection with the State’s high voltage transmission grid. $9,005 in substation improvements, such as transformer additions and substation upgrades. $7,852 in system automation improvements such as advanced metering infrastructure, and major streetlight projects.
$1,603 in donated underground electrical conduit, donated street lighting, and donated land rights and easement.
2020 compared to 2019 Investment in capital assets, net of accumulated depreciation, was $790,498, a decrease of $4,214 (0.5%). The decrease resulted from the current year depreciation offset by $19,560 in recurring expenditures such as transformer replacements, improvements to the city-wide communications network, new 230 kV station expenditures, and the Riverside Transmission Reliability Project, $10,711 in substation improvements, $5,390 in system automation improvements, and $4,617 in donated underground electrical conduit, donated street lighting, and donated land rights and easement.
Additional information regarding capital assets can be found in Note 3 of the accompanying financial statements.
DEBT ADMINISTRATION
The following table summarizes outstanding long-term debt as of June 30:
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 1.99, 2.62, and 2.24 at June 30, 2021, 2020 and 2019, respectively. This debt is backed by the revenues of the Electric Utility. Debt service coverage ratio decreased at June 30, 2021 due to a fair market value adjustment of investments and a lower overall interest rate, 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.
2021 compared to 2020 The Electric Utility’s long-term debt decreased by $22,499 (3.4%) to $639,791 as a result of current year principal payments and amortization of bond premiums.
2020 compared to 2019 Long-term debt increased by $46,160 (7.5%) to $662,290 as a result of issuance of the 2020 Pension Obligation Bond Series A, offset by current year principal payments and amortization of bond premiums.
2021 2020 2019
Revenue bonds 540,165$ 555,520$ 565,455$ Unamortized premium 47,657 50,265 52,484 Capital leases 909 1,444 2,274 Pension obligation bonds 70,951 72,966 8,400 Less: Current portion of outstanding debt (19,891) (17,905) (12,483) Total 639,791$ 662,290$ 616,130$
CC AA PP II TTAA LL AA SS SS EETT SS AA NN DD DD EEBB TT AA DD MMII NN II SSTT RR AA TTII OO NN (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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.
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS 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 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 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 it 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 in 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
CC AA PP II TTAA LL AA SS SS EETT SS AA NN DD DD EEBB TT AA DD MMII NN II SSTT RR AA TTII OO NN (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
21 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. POU’s 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 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.
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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 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 new protocols that enable 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.
The Electric Utility fulfilled its system reliability without any natural gas delivery issues during multiple heat waves from 2016 through 2020. Going forward, the Electric Utility will continue to monitor workshops and new legislation and regulations that impact the status of Aliso Canyon and its effect on the reliability of our service territory. Senate Bill 380 added Section 715 to the Public Utilities Code, which requires the CPUC to determine the range of Aliso Canyon inventory necessary to ensure safety, reliability, and just and reasonable rates. In the most recent 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 for summer 2018 and going forward, due to continuing pipeline outages on the SoCalGas system. On May 27, 2020, the CPUC granted SoCal Gas permission to withdraw natural gas from Aliso Canyon for cleanup purposes.
As of October 7, 2020, the results of the 114 injection well tests are as follows: 66 wells have completed all
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
23 required tests and have received final DOGGR approval; 27 wells have been taken out of operation; and 21 wells have been plugged and abandoned.
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 is currently working with ARP-Loyalton to comply with SB 901.
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.
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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, enhance 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- GREENHOUSE GAS EMISSIONS INTENSITY
REPORTING
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 will be conveyed to customers in the PSD report and PCL was approved on May 4, 2020. The most notable changes to the report and label are the addition
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
25 of the GHG emissions intensity and how certain energy resources will be conveyed to the customers to meet the AB 1110 requirement. Riverside continues to monitor the workshops and draft regulations for any impacts to the utility’s reporting and resources in meeting this requirement.
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, 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, 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 have or will be hosted to cover various topics and sectors within the Scoping Plan. The most notable impacts to the Electric Utility are the proposed scenarios to achieving carbon neutrality either by moving it up to 2035 or leaving it at 2045, but with restrictions on what resources would qualify as carbon neutral and how it would be accomplished. CARB indicated that cap- and-trade will not be the focus of the Scoping Plan Update, but details for implementation and/or regulatory changes would occur after the Scoping Plan Update is completed.
CARB will be hosting more workshops and plans to issue the final Scoping Plan in Fall 2022 with an adoption by Winter 2022. It is expected CARB will be issuing the next iteration of regulation changes soon thereafter. 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 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
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
annually by the CARB beginning January 1, 2020. 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”). 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 is 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 multiyear 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 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
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
27 or exceed an average of 60.00% 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 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. Riverside will continue to monitor the outcome and impacts of any upcoming workshops and regulations in meeting the new requirements.
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 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 board.
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
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
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 at the September 27, 2021 and October 12, 2021, Riverside Board and City Council, respectively.
For the wildfire fund, only voluntary 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. Riverside’s annual WMP update was filed on October 14, 2021.
FIVE-YEAR ELECTRIC RATE PLAN
On May 22, 2018, the City Council approved a five-year Electric Rate Plan, which includes system average annual with rate increases. The first annual rate increase was effective January 1, 2019 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 increase effective January 1, 2019 was 2.95%, followed by system average rate increases of 3.0% in years two through five. The Electric Rate Plan included the introduction of electric rate components over a five-year period to better align with its cost of serving customers and its revenue requirement. The Electric Rate Plan was designed to provide financial stability and correct the imbalance of costs versus revenue recovery by increasing fixed cost recovery through monthly service charges and a new network access charge to reflect the nature of underlying costs.
Pursuant to City Council direction, the first annual review of rates was conducted in February 2020 and the second annual review of rates was conducted in January 2021. Due to the unprecedented Local Emergency due to COVID-19, the City Council delayed the implementation of the third year of the Electric Rate Plan originally effective January 1, 2021 until July 1, 2021.
EE CCOO NNOO MM II CC DD EEVV EELL OO PP MM EENN TT AA NN DD GGRR EEEE NN II NN IITT IIAA TT II VVEESS 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
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
29 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.
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.
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 2020-2021 commercial energy efficiency programs saved a total of 4.9 Million kWh.
All of these efforts support organizations and companies meet 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. It is the single largest net-zero energy structure in the nation, in terms of square footage and load. (That means it will produce as much energy as it uses.)
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 Electric Utility’s grant program continues to provide assistance to local universities by providing funding for important research projects that explore new ways to advance energy technology and water conservation techniques.
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.
For more information on these economic development and green initiatives, go to GreenRiverside.com.
RR EEQQ UU EESS TT SS FF OO RR II NN FF OO RR MM AA TT IIOO NN 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, 3rd floor, Riverside, CA 92501. Additional financial information can also be obtained by visiting www.RiversidePublicUtilities.com.
EE CCOO NNOO MM II CC DD EEVV EELL OO PP MM EENN TT AA NN DD GGRR EEEE NN II NN IITT IIAA TT II VVEESS (( CCOO NN TT II NNUU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: ELECTRIC
Riverside Public Utilities Electric
STATEMENTS OF NET POSITION
June 30, June 30,
2021 2020
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 797,902$ 790,498$ Restricted assets:
Cash and investments at fiscal agent (Note 2) 59,949 64,150 Cash and cash equivalents at fiscal agent (Note 2) 7,668 33,833 Total non-current restricted assets 67,617 97,983 Other non-current assets:
Advances to other funds of the City 2,925 3,383 Unamortized purchased power (Note 11) 12,971 13,611 Regulatory assets 1,757 1,850
Total other non-current assets 17,653 18,844
Total non-current assets 883,172 907,325
CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 287,294 299,734 Accounts receivable, less allowance for doubtful accounts 2021 $6,169; 2020 $2,265 43,785 41,851
Accrued interest receivable 586 881
Inventory 971 971
Prepaid expenses 6,964 6,433
Unamortized purchased power (Note 11) 644 634 Total unrestricted current assets 340,244 350,504 Restricted assets:
Cash and cash equivalents (Note 2) 35,493 36,680 Public Benefit Programs - cash and cash equivalents (Note 2) 21,426 18,944 Public Benefit Programs receivable 1,202 983
Total restricted current assets 58,121 56,607
Total current assets 398,365 407,111
Total assets 1,281,537 1,314,436
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 15,820 83,568 Deferred outflows related to other postemployment benefits (Note 7) 2,167 1,561 Public Benefit Programs - Deferred outflows related to other postemployment benefits (Note 7) - 40 Changes in derivative values 16,228 22,623
Loss on refunding 8,567 9,091
Total deferred outflows of resources 42,782 116,883 Total assets and deferred outflows of resources 1,324,319$ 1,431,319$ See accompanying notes to the financial statements
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF NN EE TT PP OO SS IITT II OO NN EELLEECCTTRRIICC UUTTIILLIITTYY::
FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS
June 30, June 30,
2020 2019
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 790,498$ 794,712$ Restricted assets:
Cash and investments at fiscal agent (Note 2) 97,983 125,372 Other non-current assets:
Advances to other funds of the City 3,383 3,803 Unamortized purchased power (Note 11) 13,611 12,683 Regulatory assets 1,850 1,939
Total other non-current assets 18,844 18,425
Total non-current assets 907,325 938,509
CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 299,734 293,449 Accounts receivable, less allowance for doubtful accounts 2020 $2,265; 2019 $890 41,851 31,222
Advances to other funds of the City - 325 Accrued interest receivable 881 976
Inventory 971 971
Prepaid expenses 6,433 5,839
Unamortized purchased power (Note 11) 634 329 Total unrestricted current assets 350,504 333,111
Restricted assets:
Cash and cash equivalents (Note 2) 36,680 31,399 Public Benefit Programs - cash and cash equivalents (Note 2) 18,944 16,439 Public Benefit Programs receivable 983 841
Total restricted current assets 56,607 48,679
Total current assets 407,111 381,790
Total assets 1,314,436 1,320,299
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 83,568 22,300 Deferred outflows related to other postemployment benefits (Note 7) 1,561 - Public Benefit Programs - Deferred outflows related to other postemployment benefits (Note 7) 40 - Changes in derivative values 22,623 14,740
Loss on refunding 9,091 9,623
Total deferred outflows of resources 116,883 46,663 Total assets and deferred outflows of resources 1,431,319$ 1,366,962$ See accompanying notes to the financial statements
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF NN EE TT PP OO SS IITT II OO NN EELLEECCTTRRIICC UUTTIILLIITTYY::
FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS
June 30, June 30,
2020 2019
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 790,498$ 794,712$ Restricted assets:
Cash and investments at fiscal agent (Note 2) 97,983 125,372 Other non-current assets:
Advances to other funds of the City 3,383 3,803 Unamortized purchased power (Note 11) 13,611 12,683 Regulatory assets 1,850 1,939
Total other non-current assets 18,844 18,425
Total non-current assets 907,325 938,509
CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 299,734 293,449 Accounts receivable, less allowance for doubtful accounts 2020 $2,265; 2019 $890 41,851 31,222
Advances to other funds of the City - 325 Accrued interest receivable 881 976
Inventory 971 971
Prepaid expenses 6,433 5,839
Unamortized purchased power (Note 11) 634 329 Total unrestricted current assets 350,504 333,111
Restricted assets:
Cash and cash equivalents (Note 2) 36,680 31,399 Public Benefit Programs - cash and cash equivalents (Note 2) 18,944 16,439 Public Benefit Programs receivable 983 841
Total restricted current assets 56,607 48,679
Total current assets 407,111 381,790
Total assets 1,314,436 1,320,299
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 83,568 22,300 Deferred outflows related to other postemployment benefits (Note 7) 1,561 - Public Benefit Programs - Deferred outflows related to other postemployment benefits (Note 7) 40 - Changes in derivative values 22,623 14,740
Loss on refunding 9,091 9,623
Total deferred outflows of resources 116,883 46,663 Total assets and deferred outflows of resources 1,431,319$ 1,366,962$ See accompanying notes to the financial statements
(in thousands)
FINANCIAL STATEMENTS: ELECTRIC
31 Riverside Public Utilities Electric
STATEMENTS OF NET POSITION
June 30, June 30,
2021 2020
NET POSITION, LIABILITIES AND DEFERRED INFLOWS OF RESOURCES NET POSITION:
Net investment in capital assets 237,968$ 238,847$
Restricted for:
Regulatory requirements (Note 8) 16,923 16,815
Debt service (Note 8) 18,615 18,286
Public Benefit Programs 22,346 19,514
Unrestricted 201,521 221,423
Total net position 497,373 514,885
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (NOTE 4) 639,791 662,290 OTHER NON-CURRENT LIABILITIES:
Compensated absences (Note 5) 3,389 1,227
Net pension liability (Note 6) 39,233 89,792
Nuclear decommissioning liability (Note 10) 43,642 49,529 Total other postemployment benefits liability (Note 7) 11,126 10,708 Derivative instruments (Note 4) 19,968 27,451
Regulatory liability 3,461 2,373
Total non-current liabilities 120,819 181,080
CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS:
Accrued interest payable 4,085 5,872
Public Benefit Programs payable 239 304
Nuclear decommissioning liability (Note 10) 7,254 6,179 Current portion of long-term obligations (Note 4) 19,345 17,370 Total current liabilities payable from restricted assets 30,923 29,725 CURRENT LIABILITIES:
Accounts payable and other accruals 18,137 19,349 Compensated absences (Note 5) 3,793 4,635
Customer deposits 10,563 9,265
Unearned revenue 67 73
Current portion of long-term obligations (Note 4) 546 535 Total current liabilities 33,106 33,857
Total liabilities 824,639 906,952
DEFERRED INFLOWS OF RESOURCES:
Deferred inflows related to pension (Note 6) 1,714 9,220 Deferred inflows related to other postemployment benefits (Note 7) 593 262 Total deferred inflows of resources 2,307 9,482 Total net position, liabilities and deferred inflows of resources 1,324,319$ 1,431,319$ See accompanying notes to the financial statements
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF NN EE TT PP OO SS IITT II OO NN EELLEECCTTRRIICC UUTTIILLIITTYY::
FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS
June 30, June 30,
2020 2019
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 790,498$ 794,712$ Restricted assets:
Cash and investments at fiscal agent (Note 2) 97,983 125,372 Other non-current assets:
Advances to other funds of the City 3,383 3,803 Unamortized purchased power (Note 11) 13,611 12,683 Regulatory assets 1,850 1,939
Total other non-current assets 18,844 18,425
Total non-current assets 907,325 938,509
CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 299,734 293,449 Accounts receivable, less allowance for doubtful accounts 2020 $2,265; 2019 $890 41,851 31,222
Advances to other funds of the City - 325 Accrued interest receivable 881 976
Inventory 971 971
Prepaid expenses 6,433 5,839
Unamortized purchased power (Note 11) 634 329 Total unrestricted current assets 350,504 333,111
Restricted assets:
Cash and cash equivalents (Note 2) 36,680 31,399 Public Benefit Programs - cash and cash equivalents (Note 2) 18,944 16,439 Public Benefit Programs receivable 983 841
Total restricted current assets 56,607 48,679
Total current assets 407,111 381,790
Total assets 1,314,436 1,320,299
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 83,568 22,300 Deferred outflows related to other postemployment benefits (Note 7) 1,561 - Public Benefit Programs - Deferred outflows related to other postemployment benefits (Note 7) 40 - Changes in derivative values 22,623 14,740
Loss on refunding 9,091 9,623
Total deferred outflows of resources 116,883 46,663 Total assets and deferred outflows of resources 1,431,319$ 1,366,962$ See accompanying notes to the financial statements
(in thousands)
FINANCIAL STATEMENTS: ELECTRIC
Riverside Public Utilities Electric
STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION 2021 2020
OPERATING REVENUES:
Residential sales 133,460$ 121,162$
Commercial sales 68,877 68,958
Industrial sales 115,206 115,745
Other sales 4,864 4,849
Wholesale sales 27 -
Transmission revenue 32,316 34,817
Other operating revenue 12,099 13,960
Public Benefit Programs 9,252 9,478
Total operating revenues before uncollectibles 376,101 368,969 Estimated uncollectibles, net of bad debt recovery (4,034) (1,891) Total operating revenues, net of uncollectibles 372,067 367,078 OPERATING EXPENSES:
Production and purchased power 163,908 157,540
Transmission 59,770 58,830
Distribution 70,479 64,546
Public Benefit Programs 6,419 6,440
Depreciation 35,654 35,151
Total operating expenses 336,230 322,507
Operating income 35,837 44,571
NON-OPERATING REVENUES (EXPENSES):
Investment income 496 14,032
Interest expense and fiscal charges (25,901) (26,269) Gain on sale of assets 628 335
Other 6,268 1,550
Total non-operating revenues (expenses) (18,509) (10,352) Income before capital contributions and transfers out 17,328 34,219 Capital contributions 5,059 9,492
Transfers out - contributions to the City's general fund (39,899) (39,558) Total capital contributions and transfers out (34,840) (30,066) Change in net position (17,512) 4,153
NET POSITION, BEGINNING OF YEAR 514,885 510,732
NET POSITION, END OF YEAR 497,373$ 514,885$
See accompanying notes to the financial statements
For the Fiscal Years
Ended June 30,
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF RREE VV EENN UU EESS ,, EEXX PP EENN SS EE SS AA NN DD CC HH AANN GG EE SS IINN NN EE TT
PP OO SSII TT II OONN
2020 2019
OPERATING REVENUES:
Residential sales 121,162$ 116,303$
Commercial sales 68,958 69,878
Industrial sales 115,745 114,078
Other sales 4,849 4,824
Wholesale sales - 344
Transmission revenue 34,817 35,730
Other operating revenue 13,960 13,121
Public Benefit Programs 9,478 9,292
Total operating revenues before uncollectibles 368,969 363,570 Estimated uncollectibles, net of bad debt recovery (1,891) (911) Total operating revenues, net of uncollectibles 367,078 362,659 OPERATING EXPENSES:
Production and purchased power 157,540 155,264
Transmission 58,830 64,443
Distribution 64,546 58,729
Public Benefit Programs 6,440 8,933
Depreciation 35,151 34,471
Total operating expenses 322,507 321,840
Operating income 44,571 40,819
NON-OPERATING REVENUES (EXPENSES):
Investment income 14,032 13,372
Interest expense and fiscal charges (26,269) (25,053) Gain on sale of assets 335 287
Other 1,550 3,989
Total non-operating revenues (expenses) (10,352) (7,405) Income before capital contributions and transfers out 34,219 33,414 Capital contributions 9,492 6,383
Transfers out - contributions to the City's general fund (39,558) (39,886) Total capital contributions and transfers out (30,066) (33,503) Change in net position 4,153 (89)
NET POSITION, BEGINNING OF YEAR 510,732 505,412
RESTATEMENT OF NET POSITION (Note 13) - 5,409 NET POSITION, BEGINNING OF YEAR, AS RESTATED 510,732 510,821 NET POSITION, END OF YEAR 514,885$ 510,732$
See accompanying notes to the financial statements
For the Fiscal Years
Ended June 30,
(in thousands)
FINANCIAL STATEMENTS: ELECTRIC33
Riverside Public Utilities Electric
STATEMENTS OF CASH FLOWS
2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from customers and users 371,206$ 358,317$ Cash paid to suppliers and employees (295,381) (287,467) Net cash provided by operating activities 75,825 70,850 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:
Transfers out - contributions to the City's general fund (39,899) (39,558) Payment on pension obligation bonds (2,015) (1,718) Pension obligation bond issuance costs - (245)
Proceeds from pension obligation bond, used to pay into employee pension plan - 66,119 Cash paid to employee pension plan from proceeds of pension obligation bond - (65,874) Other receipts from non-operating activities 6,268 1,550 Cash received on advances to other funds of the City 458 745 Net cash provided by non-capital financing activities (35,188) (38,981) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:
Purchase of utility plant (41,453) (26,366)
Proceeds from the sale of utility plant 628 381 Principal paid on long-term obligations (15,890) (10,765) Interest paid on long-term obligations (29,680) (27,439) Capital contributions 3,456 4,875
Net cash (used) provided by capital and related financing activities (82,939) (59,314) CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from investment securities 4,201 2,190 Income from investments 791 14,127
Net cash provided by investing activities 4,992 16,317 Net change in cash and cash equivalents (37,310) (11,128) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $89,457 and $106,870 at June 30, 2020 and June 30, 2019, respectively, reported in restricted accounts) 389,191 400,319 CASH AND CASH EQUIVALENTS, END OF YEAR (including $64,587 and $89,457 at June 30, 2021 and June 30, 2020, respectively, reported in restricted accounts) 351,881$ 389,191$
RECONCILIATION OF OPERATING INCOME
TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Operating income 35,837$ 44,571$
Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation 35,654 35,151
Increase in allowance for uncollectible accounts 3,904 1,375 (Increase) in accounts receivable (6,057) (12,146) (Increase) in prepaid expenses (531) (594)
Decrease (Increase) in unamortized purchased power 630 (1,233) (Decrease) Increase in accounts payable and other accruals (1,212) 132 Increase in compensated absences 1,320 549
(Decrease) in Public Benefit Programs payable (65) (339) (Decrease) Increase in unearned revenue (6) 1 1 Increase in customer deposits 1,298 2,010
(Decrease) in decommissioning liability (4,812) (2,491) Changes in net pension liability and related deferred outflows and inflows of resources 9,682 3,364 Changes in postemployment benefits liability and related deferred outflows and inflows of resources 183 490
Net cash provided by operating activities 75,825$ 70,850$ SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:
Capital contributions - capital assets 1,603 4,617 (Decrease) Increase in fair value of investments (611) 456 See accompanying notes to the financial statements
For the Fiscal Years
Ended June 30,
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF CCAA SS HH FF LL OOWW SS
2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from customers and users 358,317$ 365,134$ Cash paid to suppliers and employees (287,467) (284,991) Net cash provided by operating activities 70,850 80,143 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:
Transfers out - contributions to the City's general fund (39,558) (39,886) Payment on pension obligation bonds (1,718) (2,018) Pension obligation bond issuance costs (245) - Proceeds from pension obligation bond, used to pay into employee pension plan 66,119 - Cash paid to employee pension plan from proceeds of pension obligation bond (65,874) - Other receipts from non-operating activities 1,550 3,989 Cash received on advances to other funds of the City 745 404 Net cash provided by non-capital financing activities (38,981) (37,511) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:
Purchase of utility plant (26,366) (43,160)
Proceeds from the sale of utility plant 381 369 Proceeds from revenue bonds, including premium - 103,303 Revenue bond refunding cost - (2,323)
Principal paid on long-term obligations (10,765) (15,269) Interest paid on long-term obligations (27,439) (27,149) Capital contributions 4,875 3,497
Bond issuance costs - (746)
Net cash (used) provided by capital and related financing activities (59,314) 18,522 CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from investment securities 2,190 2,707
Income from investments 14,127 13,412
Net cash provided by investing activities 16,317 16,119 Net change in cash and cash equivalents (11,128) 77,273 CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $106,870 and $48,359 at June 30, 2019 and June 30, 2018, respectively, reported in restricted accounts) 400,319 323,046 CASH AND CASH EQUIVALENTS, END OF YEAR (including $89,457 and $106,870 at June 30, 2020 and June 30, 2019, respectively, reported in restricted accounts) 389,191$ 400,319$
RECONCILIATION OF OPERATING INCOME
TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Operating income 44,571$ 40,819$
Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation 35,151 34,471
Increase in allowance for uncollectible accounts 1,375 261 (Increase) decrease in accounts receivable (12,146) 1,356 Decrease in inventory - 126
(Increase) in prepaid expenses (594) (530)
(Increase) in unamortized purchased power (1,233) (1,881) Increase in accounts payable and other accruals 132 7,410 Increase in compensated absences 549 245
(Decrease) increase in Public Benefit Programs payable (339) 408 Increase in unearned revenue 11 1
Increase in customer deposits 2,010 858
(Decrease) in decommissioning liability (2,491) (2,378) Changes in net pension liability and related deferred outflows and inflows of resources 3,364 (1,323) Changes in postemployment benefits liability and related deferred outflows and inflows of resources 490 300
Net cash provided by operating activities 70,850$ 80,143$ SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:
Capital contributions - capital assets 4,617 2,887 Increase in fair value of investments 456 935 Principal balance of revenue bonds refunded - 195,090 See accompanying notes to the financial statements
For the Fiscal Years
Ended June 30,
(in thousands)
Riverside Public Utilities Electric
STATEMENTS OF CASH FLOWS
2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from customers and users 371,206$ 358,317$ Cash paid to suppliers and employees (295,381) (287,467) Net cash provided by operating activities 75,825 70,850 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:
Transfers out - contributions to the City's general fund (39,899) (39,558) Payment on pension obligation bonds (2,015) (1,718) Pension obligation bond issuance costs - (245)
Proceeds from pension obligation bond, used to pay into employee pension plan - 66,119 Cash paid to employee pension plan from proceeds of pension obligation bond - (65,874) Other receipts from non-operating activities 6,268 1,550 Cash received on advances to other funds of the City 458 745 Net cash provided by non-capital financing activities (35,188) (38,981) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:
Purchase of utility plant (41,453) (26,366)
Proceeds from the sale of utility plant 628 381 Principal paid on long-term obligations (15,890) (10,765) Interest paid on long-term obligations (29,680) (27,439) Capital contributions 3,456 4,875
Net cash (used) provided by capital and related financing activities (82,939) (59,314) CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from investment securities 4,201 2,190 Income from investments 791 14,127
Net cash provided by investing activities 4,992 16,317 Net change in cash and cash equivalents (37,310) (11,128) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $89,457 and $106,870 at June 30, 2020 and June 30, 2019, respectively, reported in restricted accounts) 389,191 400,319 CASH AND CASH EQUIVALENTS, END OF YEAR (including $64,587 and $89,457 at June 30, 2021 and June 30, 2020, respectively, reported in restricted accounts) 351,881$ 389,191$
RECONCILIATION OF OPERATING INCOME
TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Operating income 35,837$ 44,571$
Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation 35,654 35,151
Increase in allowance for uncollectible accounts 3,904 1,375 (Increase) in accounts receivable (6,057) (12,146) (Increase) in prepaid expenses (531) (594)
Decrease (Increase) in unamortized purchased power 630 (1,233) (Decrease) Increase in accounts payable and other accruals (1,212) 132 Increase in compensated absences 1,320 549
(Decrease) in Public Benefit Programs payable (65) (339) (Decrease) Increase in unearned revenue (6) 1 1 Increase in customer deposits 1,298 2,010
(Decrease) in decommissioning liability (4,812) (2,491) Changes in net pension liability and related deferred outflows and inflows of resources 9,682 3,364 Changes in postemployment benefits liability and related deferred outflows and inflows of resources 183 490
Net cash provided by operating activities 75,825$ 70,850$ SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:
Capital contributions - capital assets 1,603 4,617 (Decrease) Increase in fair value of investments (611) 456 See accompanying notes to the financial statements
For the Fiscal Years
Ended June 30,
(in thousands)
NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS 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 period 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, 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 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. As of June 30, 2021, the ARO evaluation study to measure the obligation was complete in FY19-20, 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 FY20-21.
EELLEECCTTRRIICC UUTTIILLIITTYY::
NNOOTTEESS TTOO TTHHEE FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
35 In June 2017, the GASB issued Statement No. 87, Leases. The objective of this Statement is to better meet the information needs of financial statement users by improving accounting and financial reporting for leases. The Statement requires recognition of certain lease assets and liabilities for leases that previously were classified as operating leases. The requirements of this Statement are effective for reporting periods beginning after June 15, 2021. The Department is evaluating the impact of this standard.
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 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 $16,117 at June 30, 2021, and $14,115 at June 30, 2020.
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
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 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 NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS (( CCOO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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 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's cash and investments previously held at and administered by Southern California Public Power Authority (SCPPA) were used in entirety during the 19- 20 fiscal year to pay for power, transmission, capital and/or operating costs relating to projects in which the Electric Utility was a participant, or other expenditures owed to SCPPA.
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, 2021, 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 San Onofre Generating Stations (SONGS).
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, 2021 and 2020 were as follows: Additional Decommissioning Liability Reserve $13,838 and $11,710, Customers Deposits $5,184 and $4,748, Capital Repair and Replacement Reserve $4,650 and $5,579, Electric Reliability Reserve $81,775 and $79,133, Mission Square Improvement Reserve $1,063 and $1,836, and Dark Fiber Reserve $4,319 and $3,633. In June 2017, the Board of Public Utilities and City Council approved the establishment of a bond defeasance designated cash reserve account and authorized the transfer of settlements and cost recoveries in the amount of $11,244 to the designated reserve for bond defeasance. In fiscal year June 30, 2018, bond defeasance reserve has been fully utilized to partially defease existing revenue bonds. The combined total NN OO TT EE 11.. SSUU MM MM AA RRYY OO FF SSIIGG NNII FF II CCAA NN TT AA CCCCOO UU NN TTII NN GG PP OO LLII CC II EESS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
37 for these reserves was $110,829 and $106,639 at June 30, 2021 and 2020, 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, 2021 and 2020 are $2,925 and $3,383, 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, 2021 and 2020 was $10,563 and $9,265, respectively.
COMPENSATED ABSENCES
The accompanying financial statements include accruals for salaries, fringe benefits and compensated absences due to employees at June 30, 2021 and 2020. 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 $7,182 at June 30, 2021 and $5,862 at June 30, 2020.
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.
NN OO TT EE 11.. SSUU MM MM AA RRYY OO FF SSIIGG NNII FF II CCAA NN TT AA CCCCOO UU NN TTII NN GG PP OO LLII CC II EESS (( CC OONN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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.
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, including the Utility Plant with a limit of $1 billion and an additional $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, 2021, 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, 2021 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 $877 and $967 for the years ended June 30, 2021 and 2020, 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 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 NN OO TT EE 11.. SSUU MM MM AA RRYY OO FF SSIIGG NNII FF II CCAA NN TT AA CCCCOO UU NN TTII NN GG PP OO LLII CC II EESS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
39 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 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
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, 2021 and 2020, $39,899 and $39,558, respectively was transferred, representing 11.5 percent.
Additional information can be found in Note 13 of the accompanying financial statements.
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.
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 normally adopts the Electric Utility’s budget NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS (( CCOO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
in June biennially via resolution, however due to the impact of COVID-19, the City adopted an emergency fiscal year 20/21 budget.
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.
NN OO TT EE 22.. CCAA SSHH AANN DD IINN VV EE SSTT MM EE NNTT SS Cash and investments at June 30, 2021 and 2020, consist of the following (in thousands):
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.
June 30, 2021 June 30, 2020
Equity interest in City Treasurer's investment pool 344,213$ 355,358$ Cash and investments at fiscal agent 59,949 64,150 Cash and cash equivalents at fiscal agent 7,668 33,833 Total cash and investments 411,830$ 453,341$
The amounts above are reflected in the accompanying financial statements as:
June 30, 2021 June 30, 2020
Unrestricted cash and cash equivalents 287,294$ 299,734$ Restricted cash and cash equivalents 56,919 55,624 Restricted cash and investments at fiscal agent 59,949 64,150 Restricted cash and cash equivalents at fiscal agent 7,668 33,833 Total cash and investments 411,830$ 453,341$
Fair Value
NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS (( CCOO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
41 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, 2021 and 2020:
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.
Investment Type
June 30,
2021
Fair Value
Quoted Prices in
Active Markets for
Ide ntica l Asse ts
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable Inputs
(Level 3)
Inve stm e nts
not Subject
to Fair Value
Hierarchy
Held by fiscal agent
Money market funds 11,247 $ -$ -$ -$ 11,247$ Asset-backed securities 1 , 1 7 4 - 1,174 - - Investment contracts 10,761 - - - 10,761 Commercial paper 1 , 0 0 0 - 1,000 - - US Treasury notes/bonds 28,615 - 28,615 - - Federal agency obligations 2 , 6 6 6 - 2,666 - - Corp medium term notes 10,121 - 10,121 - - Supranational securities 2 , 0 3 3 - 2,033 - - City Treasurer's investment pool 1
Money market funds 3 , 3 0 7 - - - 3,307 Joint powers authority pools 56,862 56,862 - - - Local agency investment fund 62,530 - - - 62,530 Mortgage pass-through securities 13,976 - 13,976 - - Asset-backed securities 10,551 - 10,551 - - US Treasury obligations 75,480 - 75,480 - - Federal agency obligations 56,066 - 56,066 - - Medium-term corporate notes 49,582 - 49,582 - - Supranational securities 11,914 - 11,914 - - Neg certificate of deposit 3 , 9 4 5 - 3,945 - - Total 411,830 $ 56,862$ 267,123$ -$ 87,845$ Investment Type
June 30,
2020
Fair Value
Quoted Prices in
Active Markets for
Ide ntica l Asse ts
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable Inputs
(Level 3)
Inve stm e nts
not Subject
to Fair Value
Hierarchy
Held by fiscal agent
Money market funds 56,443 $ -$ -$ -$ 56,443$ US Treasury notes/bonds 27,726 - 27,726 - - Investment contracts 10,761 - - - 10,761 Corp medium term notes 3 , 0 5 3 - 3,053 - - City Treasurer's investment pool 1
Money market funds 2 , 7 0 1 - - - 2,701 Joint powers authority pools 86,432 86,432 - - - Local agency investment fund 71,785 - - - 71,785 Mortgage pass-through securities 15,711 - 15,711 - - Asset-backed securities 2 , 4 4 6 - 2,446 - - US Treasury obligations 98,717 - 98,717 - - Federal agency obligations 40,947 - 40,947 - - Medium-term corporate notes 32,641 - 32,641 - - Supranational securities 2 , 0 6 5 - 2,065 - - Neg certificate of deposit 1 , 9 1 3 - 1,913 - - Total 453,341 $ 86,432$ 225,219$ -$ 141,690$ NN OO TT EE 22.. CC AA SSHH AA NN DD IINN VVEE SSTT MM EE NNTT SS (( CCOO NN TT II NNUU EE DD)) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
Cash and investments distribution by maturities as of June 30, 2021 and 2020, are as follows:
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.
June 30, 2021 12 Months 13 to 36 37 to 60 More than
Investment Type Fair Value or less Months Months 60 Months Held by fiscal agent
Money market funds 11,247$ 11,247$ -$ -$ -$ Asset-backed securities 1,174 - 240 934 - Investment contracts 10,761 - - - 10,761 Commercial paper 1,000 1,000 - - - US Treasury notes/bonds 28,615 12,145 9,334 7,136 - Federal agency obligations 2,666 - 2,666 - - Corp medium term notes 10,121 - 998 9,123 - Supranational securities 2,033 - - 2,033 - City Treasurer's investment pool 1
Money market funds 3,307 3,307 - - - Joint powers authority pools 56,862 56,862 - - - Local agency investment fund 62,530 62,530 - - - Mortgage pass-through securities 13,976 4,643 8,588 745 - Asset-backed securities 10,551 - 2,990 7,561 - US Treasury obligations 75,480 11,512 48,259 15,709 - Federal agency obligations 56,066 6,393 20,555 29,118 - Medium-term corporate notes 49,582 7,652 9,396 32,534 - Supranational securities 11,914 - - 11,914 - Neg certificate of deposit 3,945 3,945 - - - Total 411,830$ 181,236$ 103,026$ 116,807$ 10,761$ Remaining Maturity (In Months)
June 30, 2020 12 Months 13 to 36 37 to 60 More than
Investment Type Fair Value or less Months Months 60 Months Held by fiscal agent
Money market funds 56,443$ 56,443$ -$ -$ -$ US Treasury notes/bonds 27,726 9,104 18,622 - - Investment contracts 10,761 - - - 10,761 Corp medium term notes 3,053 3,053 - - - City Treasurer's investment pool 1
Money market funds 2,701 2,701 - - - Joint powers authority pools 86,432 86,432 - - - Local agency investment fund 71,785 71,785 - - - Mortgage pass-through securities 15,711 - 10,708 5,003 - Asset-backed securities 2,446 - - 2,446 - US Treasury obligations 98,717 18,287 45,908 34,522 - Federal agency obligations 40,947 3,866 16,015 21,066 - Medium-term corporate notes 32,641 2,559 19,169 10,913 - Supranational securities 2,065 - - 2,065 - Neg certificate of deposit 1,913 951 962 - - Total 453,341$ 255,181$ 111,384$ 76,015$ 10,761$ Remaining Maturity (In Months)
NN OO TT EE 22.. CC AA SSHH AA NN DD IINN VVEE SSTT MM EE NNTT SS (( CCOO NN TT II NNUU EE DD)) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
43 Presented below is the actual rating as of June 30, 2021 and 2020 for each investment type:
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.
Investment Type
June 30, 2021
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds 11,247$ 3,038$ -$ 8,164$ 45$ Asset-backed securities 1,174 1,174 - - - Investment contracts 10,761 - - - 10,761 Commercial paper 1,000 - - - 1,000 US Treasury notes/bonds 28,615 28,615 - - - Federal agency obligations 2,666 - 2,666 - - Corp medium term notes 10,121 - 2,879 6,547 695 Supranational securities 2,033 2,033 - - - City Treasurer's investment pool 1
Money market funds 3,307 1,153 - - 2,154 Joint powers authority pools 56,862 56,862 - - - Local agency investment fund 62,530 - - - 62,530 Mortgage pass-through securities 13,976 13,976 - - - Asset-backed securities 10,551 8,577 - - 1,974 US Treasury obligations 75,480 75,480 - - - Federal agency obligations 56,066 53,827 - - 2,239 Medium-term corporate notes 49,582 - 18,008 27,537 4,037 Supranational securities 11,914 8,033 - - 3,881 Neg certificate of deposit 3,945 - - - 3,945 Total 411,830$ 252,768$ 23,553$ 42,248$ 93,261$ Rating as of Year End
Investment Type
June 30, 2020
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds 56,443$ 22,521$ -$ 33,879$ 43$ US Treasury notes/bonds 27,726 27,726 - - - Investment contracts 10,761 - - - 10,761 Corp medium term notes 3,053 - 3,053 - - City Treasurer's investment pool 1
Money market funds 2,701 241 - - 2,460 Joint powers authority pools 86,432 86,432 - - - Local agency investment fund 71,785 - - - 71,785 Mortgage pass-through securities 15,711 - - - 15,711 Asset-backed securities 2,446 - - - 2,446 US Treasury obligations 98,717 - 98,717 - - Federal agency obligations 40,947 - 37,646 - 3,301 Medium-term corporate notes 32,641 - 14,770 17,871 - Supranational securities 2,065 2,065 - - - Neg certificate of deposit 1,913 - - - 1,913 Total 453,341$ 138,985$ 154,186$ 51,750$ 108,420$ Rating as of Year End
NN OO TT EE 22.. CC AA SSHH AA NN DD IINN VVEE SSTT MM EE NNTT SS (( CC OO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
NN OO TT EE 33.. UU TT II LLII TT YY PP LL AANN TT
The following is a summary of changes in utility plant during the fiscal years ended June 30, 2021 and 2020 (in thousands):
Balance Balance Balance
As of Retirements / As of Re tire me nts/ As of
6/30/2019 Additions Transfers 6/30/2020 Additions Transfers 6/30/2021 Production 267,873$ 3,967 $ (3,752)$ 268,088$ 1,160 $ -$ 269,248$ Transmission 45,109 1 5 (40) 45,084 3,995 - 49,079 Distribution 656,924 25,057 (1,020) 680,961 26,601 (755) 706,807 General 112,468 2,051 - 114,519 3,786 (609) 117,696 Intangibles 21,757 2 2 9 - 21,986 - - 21,986 Depreciable utility plant 1,104,131 31,319 (4,812) 1,130,638 35,542 (1,364) 1,164,816 Less accumulated depreciation:
Production (97,664) (8,978) 3,752 (102,890) (8,988) - (111,878) Transmission (19,669) (886) 40 (20,515) (886) - (21,401) Distribution (267,372) (18,065) 974 (284,463) (18,740) 748 (302,455) General (45,218) (4,796) - (50,014) (4,602) 609 (54,007) Intangibles (8,483) (2,426) - (10,909) (2,438) - (13,347) Accumulated depreciation (438,406) (35,151) 4,766 (468,791) (35,654) 1,357 (503,088) Net depreciable utility plant 665,725 (3,832) (46) 661,847 (112) (7) 661,728 Land 53,029 3 - 53,032 1 0 - 53,042 Intangibles, non-amortizable 10,651 - - 10,651 - - 10,651 Construction in progress 65,307 26,366 (26,705) 64,968 41,463 (33,950) 72,481 Nondepreciable utility plant 128,987 26,369 (26,705) 128,651 41,473 (33,950) 136,174 Total utility plant 794,712$ 22,537 $ (26,751)$ 790,498$ 41,361 $ (33,957)$ 797,902$ NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
45 NN OO TT EE 44.. LLOO NN GG -- TTEE RR MM OOBB LLII GGAA TTII OO NN SS The following is a summary of changes in long-term obligations during the fiscal years ended June 30, 2021 and 2020 (in thousands):
Long-term debt consists of the following (in thousands):
PENSION OBLIGATION BONDS PAYABLE
Balance Balance Balance Due
As of As of As of Within
6/30/2019 Additions Reductions 6/30/2020 Additions Reductions 6/30/2021 One Year Revenue bonds 576,914 $ 41,025 $ (12,154)$ 605,785 $ - $ (17,963)$ 587,822 $ 16,035 $ Pension obligation bonds 8,400 66,284 (1,718) 72,966 - (2,015) 70,951 3,310 Direct Borrowings: -
Private placement revenue bonds 1 41,025 - (41,025) - - - - - Leased purchase 2,274 - (830) 1,444 - (535) 9 0 9 546 Total long-term obligations 628,613 $ 107,309 $ (55,727)$ 680,195 $ - $ (20,513)$ 659,682 $ 19,891 $ 1 In FY19-20, the bonds were remarketed as public securities from private placement revenue bonds in order to obtain a lower rate. The structure of the bonds and the existing swap remain the same. For June 30, 2021 outstanding balance refer to the Revenue Bonds Payable section of the Note 4.
June 30, 2021 June 30, 2020
5,940$ 6,847$
65,011 66,119
Total pension obligation bonds payable 70,951 72,966 $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. $201,080 2020 Taxable Pension Obligation Bonds Series A (Misce lla ne ous):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.
NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
REVENUE BONDS PAYABLE
June 30, 2021 June 30, 2020
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, 2021 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, 2021 was 3.1 percent). Partially refunded $11,775 on July 25, 2013 with the 2013 Electric Revenue Refunding Bonds.
Partially refunded $8,925 on April 1, 2019 with 2019A Electric 32,150 32,150
130,990 133,290
37,450 39,275
37,275 38,155
267,835 278,185
Total electric revenue bonds payable 540,165 555,520 Total electric revenue and pension obligation bonds payable 611,116 628,486 Unamortized bond premium 47,657 50,265
Total electric revenue and pension obligation bonds payable, including bond premium 658,773 678,751
Less current portion of revenue and pension obligation bonds payable (19,345) (17,370) Total long-term electric revenue and pension obligation bonds payable 639,428$ 661,381$
1 In FY19-20, the bonds were remarketed as public securities from private placement revenue bonds in order to obtain a lower rate. The structure of the bonds and the existing swap remain the same. For June 30, 2021 outstanding balance refer to the Revenue Bonds Payable section of the Note 4. $79,080 2013 Electric Revenue Refunding Series A Bonds: fixed rate bonds due in annual principal installments from $835 to $2,625 through October 1, 2043, interest from 3.5 to 5.3 percent
$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
$141,840 2008 Electric Refunding/Revenue Bonds:
$56,450 2011 Electric Revenue/Refunding Series A Bonds 1: fixed rate bonds due in annual principal installments from $725 to $5,175 through October 1, 2035, interest of 3.2 percent
$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
NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
47 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 pl ans. It is estimated the issuance w ill save the City’s General Fund $7.6M in pension costs in FY 2022 with a projected overall savings of $178.5 million through 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 Electric Ut ility'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 $70,951 and $72,966 as of June 30, 2021 and 2020, respectively. The bond proceeds were deposited with CalPERS to fund the unfunded actuarial accrued liability for non-safety employees. For more discussion relating to the City’s pension obligation bond issuance, see the notes to the City’s financial statements in the City’s Annual Comprehensive Financial Report for the fiscal year ended June 30, 2021.
Remaining pension obligation bond debt service payments will be made from revenues of the Electric Fund.
Annual debt service requirements to maturity as of June 30, 2021 are as follows (in thousands):
All electric revenue bonds are covenanted per the Amended and Restated Resolution No. 17662 (Electric) Master Resolution that upon the occurrence and continuation of an event of default, the owners of 25% in aggregate amount of Bond Obligation may, by written notice to the City, declare the entire unpaid principal and accreted value of the bonds due and payable should the City fail to pay its debts as they become due or upon the entry of any decree or order of bankruptcy of the City.
Fis cal Year Principal Interes t Total
2022 3,310$ 2,196$ 5,506 $
2023 4,232 2,132 6,364
2024 5,118 2,044 7,162
2025 5,675 1,930 7,605
2026 5,839 1,797 7,636
2027-2031 16,955 7,067 24,022
2032-2036 15,933 4,546 20,479
2037-2041 12,589 1,611 14,200
2042-2046 1,300 67 1,367
Total 70,951$ 23,390 $ 94,341$
NNOOTT EE 44 .. LLOO NNGG --TT EE RR MM OO BB LLII GG AA TT II OO NNSS (( CCOO NNTT II NNUUEE DD)) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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, 2021 are as follows (in thousands):
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, 2021 and 2020, 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.
LINE OF CREDIT
On February 1, 2019, the City entered into a subordinate line of credit agreement with U.S. Bank, National Association. 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 $35,000 for purposes of the capital or operating financial needs of the Electric System. There were no borrowings against the line as of June 30, 2021.
Fis cal Year Principal Interes t Total
2022 16,035$ 24,954$ 40,989 $
2023 16,760 24,174 40,934
2024 17,515 23,362 40,877
2025 18,335 22,488 40,823
2026 12,580 21,580 34,160
2027-2031 111,740 94,522 206,262
2032-2036 130,045 67,788 197,833
2037-2041 172,330 33,900 206,230
2042-2046 29,105 7,310 36,415
2047-2051 15,720 1,205 16,925
Premium 47,657 - 47,657
Total 587,822$ 321,283$ 909,105 $
Fis cal Year Ended
Description of
Pledged Revenues
Annual Amount of
Pledged Revenue
(net of expens es ) 1, 2
Annual Debt
Service
Payments
Debt Service
Coverage
Ratio
June 30, 2021 Electric revenues 89,371$ 44,923$ 1.99 June 30, 2020 Electric revenues 101,328$ 38,633$ 2.62 1 Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of 9,682 and $3,364 for June 30, 2021 and 2020, respectively.
2 Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $183 and $490 for June 30, 2021 and 2020, respectively.
NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
49 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:
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. The Electric Utility would be required to pay annual interest equal to 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. 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.
A summary of the derivative activity for the year ended June 30, 2021 is as follows:
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 $5,175 (2011 Series A) until De bt Issue LOC Provider
LOC
Expiration
Date
Annual
Commitment
Fee
2008 Electric Refunding/Revenue Bonds Series A Barclays Bank, PLC 2024 0.395% 2008 Electric Refunding/Revenue Bonds Series C Barclays Bank, PLC 2024 0.395% 2011 Electric Refunding/Revenue Bonds Series A Bank of America N.A. 2023 0.295% Fair Value Change in
Notional as of Fair Value
Amount 6/30/2021 for Fiscal Year
2008 Electric Refunding/Revenue Bonds Series A 34,465$ (4,731)$ 1,767$ 2008 Electric Refunding/Revenue Bonds Series C 32,150$ (7,520)$ 2,767$ 2011 Electric Refunding/Revenue Bonds Series A 37,450$ (7,716)$ 2,949$ NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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, 2021, rates were as follows:
Fair value: As of June 30, 2021, in connection with all swap agreements, the transactions had a total negative fair value of ($19,967). 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, 2021, 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, 2021, 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.
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 Electric Utility if either counterparty’s 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, 2021, 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.
2008 Electric 2008 Electric 2011 Electric
Refunding/Revenue Refunding/Revenue Refunding/Revenue
Series A Bonds Series C Bonds 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 + 12bps (0.58168%) (0.58230%) (0.60582%) Net interest rate swap payments 2.52932% 2.62170% 2.59518% Variable-rate bond coupon payments 0.48121% 0.48066% 0.58006% Synthetic interest on bonds 3.01053% 3.10236% 3.17523%
NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
51 DIRECT BORROWINGS
LEASE PURCHASE FINANCING
The Electric Utility has entered into sixteen purchase lease agreements as a lessee for financing sixteen compressed natural gas heavy duty service trucks. All leases 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 leases is $5,715 with depreciation over the seven-year terms of the leases using the straight-line method. As of June 30, 2021 and 2020, the total liability was $909 and $1,444, respectively, with the current portion included in accounts payable and other accruals. The remaining annual lease payments for the life of the leases are $559 in fiscal year ended June 30, 2022, and $366 in fiscal year ended June 30, 2023. Total outstanding lease payments are $925, with $909 representing the present value of the net minimum lease payments and $16 representing interest.
NN OO TT EE 55.. CCOO MMPP EENN SS AA TT EE DD AA BB SSEE NN CCEESS A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.
Below is a summary of changes in Compensated absences for the Electric Utility during the fiscal year.
Fiscal Year
Ending Interest Rate
June 30, Principal Interes t Swaps , Net Total
2022 1,900$ 584$ 2,904$ 5,388$ 2023 1,950 571 2,843 5,364 2024 725 563 2,811 4,099 2025 725 558 2,788 4,071 2026 7,450 528 2,633 10,611 2027-2031 42,940 1,992 9,821 54,753 2032-2036 48,375 673 3,284 52,332 Total 104,065$ 5,469$ 27,084$ 136,618$ Variable-Rate Bonds
Balance Balance Balance Due
As of As of As of Within
6/30/2019 Additions Reductions 6/30/2020 Additions Reductions 6/30/2021 One Year Compensated absences 5,313$ 4,750$ (4,201)$ 5,862$ 4,416$ (3,096)$ 7,182$ 3,793$ NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RREE TT II RREE MM EENN TT PP LLAA NN
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 percent 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:
1 st 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.
2 nd 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.
NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
53 3 rd 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.
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, 2020 and 2019, the following employees, City-wide, were covered by the benefit terms of the Plan:
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, 2021, the net pension liability of the Plan is measured as of June 30, 2020, using an annual actuarial valuation as of June 30, 2019 rolled forward to June 30, 2020 using standard update procedures. For fiscal year ended June 30, 2020, the net pension liability of the Plan is measured as of June 30, 2019, using an annual actuarial valuation as of June 30, 2018 rolled forward to June 30, 2019 using standard update procedures. A summary of principal assumptions and methods used to determine the net pension liability is shown below.
June 30, 2020 June 30, 2019
Inactive employees or beneficiaries
currently receiving benefits 2,301 2,252
Inactive employees entitled to but
not yet receiving benefits 1,427 1,411
Active employees 1,559 1,606
Meas urement Date
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
ACTUARIAL ASSUMPTIONS
The total pension liabilities in the June 30, 2020 and 2019 actuarial valuations were determined using the following actuarial assumptions:
CHANGES IN ASSUMPTIONS
There were no changes in assumptions for the measurement date of June 30, 2020.
DISCOUNT RATE
The discount rate used to measure the Plan’s total pension liability was 7.15 percent measurement date as of June 30, 2020 and 2019. 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.
LONG-TERM DISCOUNT 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 as well as the expected pension fund cash flows. Using historical returns Mis cellaneous - Current Year Mis cellaneous - Prior Year Valuation Date June 30, 2019 June 30, 2018
Measurement Date June 30, 2020 June 30, 2019
Actuarial Cost Method Entry-Age Normal Cost Method Entry-Age Normal Cost Method Actuarial Assumptions
Discount Rate 7.15% 7.15%
Inflation 2.50% 2.50%
Salary Increase Varies by entry age and service Varies by entry age and service Mortality Rate Table1
Post Retirement Benefit
Increase
The lesser of contract COLA or
2.50% until Purchasing Power
Protection Allowance floor on
purchasing power applies, 2.50%
thereafter
The lesser of contract COLA or
2.50% until Purchasing Power
Protection Allowance floor on
purchasing power applies, 2.50%
thereafter
Derived using CalPERS’ membership data for all funds.
1 The mortality table used w as developed based on CalPERS-specific data. The probabilities of mortality are based on the 2017 CalPERS Experience Study for the period from 1997 to 2015. Pre-retirement and Post-retirement mortality rates include 15 years of projected mortality improvement using 90% of Scale MP-2016 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 December 2017 that can be found on the CalPERS w ebsite.
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
55 of all of the funds’ asset classes, expected compound (geometric) returns were calculated over the short- term (first 10 years) and the long-term (11+ years) using a building-block approach. Using the expected nominal returns for both short-term and long-term, the present value of benefits was calculated for each fund. The expected rate of return was set by calculating the rounded single equivalent expected return that arrived at the same present value of benefits for cash flows as the one calculated using both short-term and long-term returns. The expected rate of return was then set equal to the single equivalent rate calculated above and adjusted to account for assumed administrative expenses. The expected real rates of return by asset class are as follows:
Current Target Real Return Real Return
Asse t Cla ss (1) Allocation Years 1 - 10 (2) Years 11+ (3) Global Equity 50.00% 4.80% 5.98%
Fixed Income 28.00% 1.00% 2.62%
Inflation Assets 0.00% 0.77% 1.81%
Private Equity 8.00% 6.30% 7.23%
Real Assets 13.00% 3.75% 4.93%
Liquidity 1.00% 0.00% -0.92%
(2) An expected inflation of 2.00% used for this period. (3) An expected inflation of 2.92% used for this period.
Current Target Real Return Real Return
Asse t Cla ss (1) Allocation Years 1 - 10 (2) Years 11+ (3) Global Equity 50.00% 4.80% 5.98%
Fixed Income 28.00% 1.00% 2.62%
Inflation Assets 0.00% 0.77% 1.81%
Private Equity 8.00% 6.30% 7.23%
Real Assets 13.00% 3.75% 4.93%
Liquidity 1.00% 0.00% -0.92%
(2) An expected inflation of 2.00% used for this period. (3) An expected inflation of 2.92% used for this period.
June 30, 2020 Measurement Date
(1) In the System's CAFR, 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.
June 30, 2019 Measurement Date
(1) In the System's CAFR, 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.
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
CHANGES IN THE NET PENSION LIABILITY
The changes in the Electric Utility’s proportionate share of the net pension liability as of June 30, 2021 (measurement date June 30, 2020) and 2020 (measurement date June 30, 2019) for the Plan are as follows:
SENSITIVITY OF THE NET PENSION LIABILITY 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 7.15 percent, 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:
Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports.
PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES
RELATED TO PENSION
For the fiscal years ended June 30, 2021 and 2020, the Electric Utility recognized pension expense of $18,267 and $16,125, respectively. At June 30, 2021 and 2020, the Electric Utility reported deferred outflows of resources and deferred inflows of resources related to pension from the following sources:
Net Pension Proportion of
June 30, 2021 Liability the Plan
Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 39,233$ 32.68% Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 89,792 30.73% Changes - Increase / (Decrease) (50,559) 1.95%
June 30, 2020
Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 89,792$ 30.73% Proportion - Reporting date June 30, 2019 (Measurement Date June 30, 2018) 84,468 30.32% Changes - Increase / (Decrease) 5,324 0.41%
Discount Rate
- 1%
(6.15%)
Current
Discount Rate
(7.15%)
Discount Rate
+1%
(8.15%)
Discount Rate
- 1%
(6.15%)
Current
Discount Rate
(7.15%)
Discount Rate
+1%
(8.15%)
Electric Utility's
proportionate share of the
Plan's net pension laibility
$ 104,813 $ 39,233 $ (14,762) $ 149,315 $ 89,792 $ 40,832 Measurement Date
June 30, 2020
Meas urement Date
June 30, 2019
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
57 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, 2021.
Amounts reported as deferred outflows of resources and deferred inflows of resources related to pensions will be recognized as pension expense as follows:
NN OO TT EE 77.. OO TT HH EE RR PPOO SS TT-- EEMM PP LL OO YY MM EENN TT BB EENN EEFF II TT SS (( OO PP EEBB ))
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 benefit to eligible retirees and beneficiaries. Retiree and spousal coverage terminate when the Deferred
Outflows of
Re source s
Deferred
Inflows of
Re source s
Deferred
Outflows of
Re source s
Deferred
Inflows of
Re source s
Pension contributions subsequent to
measurement date $ 8,586 -$ $ 78,636 -$ Change in Assumptions - (1,125) 3,609 (4,292) Difference between expected and actual
experience 2,307 (589) 1,323 (3,494) Net difference between projected and actual
earnings on pension plan investments 4,927 - - (1,434) Total 15,820$ (1,714)$ 83,568$ (9,220)$ June 30, 2021 June 30, 2020
Year Ended
June 30
Deferred Outflows/
(Inflows) of
Re source s
2022 (1,384)$
2023 2,319
2024 2,578
2025 2,007
2026 -
Thereafter -
Total 5,520$
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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, 2020 and 2019, the following employees, City-wide, were covered by the benefit terms:
ACTUARIAL ASSUMPTIONS
The total OPEB liability was determined by actuarial valuation as of June 30, 2020 and 2019 using the following actuarial assumptions:
Meas urement Date Meas urement Date
June 30, 2020 June 30, 2019
Inactive plan members or beneficiaries
currently receiving benefits
274 274
Inactive plan members entitled to but
not yet receiving benefits
- -
Active plan members 2,138 2,138
Valuation Date
Measurement Date
Actuarial Cost Method
Actuarial Assumptions
Discount rate
Inflation rate
Payroll Increases:
Merit Increases:
Mortality
Heathcare Trend Rates Fiscal Year
End Future Year Trend
Fiscal Year
End Future Year Trend
2020 - 2020 6.50%
2021 6.25% 2021 6.25%
2022 6.00% 2022 6.00%
2023 5.75% 2023 5.75%
2024 5.50% 2024 5.50%
2025 5.25% 2025 5.25%
2026 5.00% 2026 5.00%
2027 4.75% 2027 4.75%
2028 + 4.50% 2028 + 4.50%
3.0%, plus merit increases based on the 3.0%, plus merit increases based on the Merit increases from the CalPERS pension Merit increases from the CalPERS pension SOA Pub-2010 General Total Dataset
Headcount Weighted Mortality Table fully
generational using Scale MP-2019
SOA Pub-2010 General Total Dataset
Headcount Weighted Mortality Table fully
generational using Scale MP-2019
Pay-as-you-go for Pay-as-you-go for
3.51% as of July 1, 2019 and 2.66% as of
June 30, 2020 for accounting disclosure
purposes. Refer to the
Discussion of Discount Rates section for more
information on selection of the discount rate.
3.51% per annum. This discount rate is the
maximum of the range of 3-20 year municipal
bond rate indices: S&P Municipal Bond 20
Year High Grade Rate Index, Bond Buyer 20-
Bond GO index, Fidelity GO AA 20 Year Bond
Index.
3% per annum 3% per annum
Mis cellaneous - Current Year Mis cellaneous - Prior Year June 30, 2019 June 30, 2018
June 30, 2020 June 30, 2019
NN OO TT EE 77.. OO TT HH EE RR PPOO SS TT-- EE MMPP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CC OONN TT II NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
59 CHANGES OF ASSUMPTIONS
In 2020, the discount rate was changed from 3.51 percent to 2.66 percent.
SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN HEALTHCARE COST
TREND RATES
The following presents the Electric Utility’s, including Public Benefits, proportionate share of the City’s total OPEB liability, calculating using the healthcare trend rate of 6.25% and 6.50% for measurement date as of June 30, 2020 and June 30, 2019 respectively, 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:
SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN DISCOUNT RATES The following presents the Electric Utility’s, including Public Benefits, proportionate share of the City’s total OPEB liability, calculating using the discount rate of 2.66% and 3.51% for measurement date as of June 30, 2020 and 2019 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 :
CHANGE IN TOTAL OPEB LIABILITY
For fiscal year ended June 30, 2021 and 2020, the Electric Utility’s, including Public Benefits, recognized total OPEB expense of $183 and $490 respectively. The following table shows the change in the Electric Utility’s, including Public Benefits, proportionate share of the City’s total OPEB liability for the year ended June 30, 2021 (measurement date June 30, 2020):
1% Decrease
Current
healthcare cost
trend rate 1% Increas e 1% Decreas e
Current
healthcare cost
trend rate 1% Increase
Electric Utility's
proportionate share of
total OPEB laibility
$ 9,726 $ 11,126 $ 12,803 $ 9,472 $ 10,708 $ 12,180 Meas urement Date
June 30, 2020
Meas urement Date
June 30, 2019
1% Decrease
(1.66%)
Current Discount
Rate
(2.66%)
1% I ncre a se
(3.66%)
1% Decrease
(2.51%)
Current Discount
Rate
(3.51%)
1% Increase
(4.51%)
Electric Utility's
proportionate share of
total OPEB laibility
$ 12,225 $ 11,126 $ 10,134 $ 11,837 $ 10,708 $ 9,705 Meas urement Date
June 30, 2020
Meas urement Date
June 30, 2019
NN OO TT EE 77.. OO TT HH EE RR PPOO SS TT-- EE MMPP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2021, the Electric Utility, including Public Benefits, reported deferred inflows of resources related to OPEB from the following sources:
Amounts reported as deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:
Net OPEB Proportion of
June 30, 2021 Liability the Plan
Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 11,126$ 21.28% Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 10,708 21.41% Changes - Increase / (Decrease) 418 -0.13% June 30, 2020
Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 10,708$ 21.41% Proportion - Reporting date June 30, 2019 (Measurement Date June 30, 2018) 8,572 22.36% Changes - Increase / (Decrease) 2,136 -0.95% Deferred Outflows
of Resources
Deferred Inflows of
Re source s
42$ (395)$
Changes of assumptions 1,722 (198) Contributions subsequent to
measurement date 403 -
Total 2,167$ (593)$
Difference between expected and
actual experience
Deferred Outflows/
Year Ended (Inflows) of
June 30 Resources
2022 150$
2023 150
2024 150
2025 150
2026 187
Therafter 384
Total 1,171$
NN OO TT EE 77.. OO TT HH EE RR PPOO SS TT-- EE MMPP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CC OONN TT II NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
61 NN OO TT EE 88.. RREE SS TT RRII CCTT EE DD NN EETT PP OO SSII TT IIOONN
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. 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.
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).
NN OO TT EE 99.. JJOO IINN TT LLYY-- GG OO VV EERR NN EEDD OO RRGG AA NN II ZZ AA TT II OONN SS
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, 2021 and 2020, the Electric Utility paid approximately $22,301 and $28,011, 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 consist 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.
NN OO TT EE 1100 .. JJOO IINN TT LLYY-- OO WW NN EEDD UU TT IILLII TT YY PP RROO JJ EE CCTT –– SSOONN GG SS 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 NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
remain associated with certain of its costs, including those associated with the units’ shutdown and decommissioning (see Note 1 for nuclear decommissioning liability).
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 the SCE’s decommissioning cost estimate document as of March 2018, total decommissioning costs for Units 2 and 3 are estimated at $4.7 billion of which the Electric Utility’s share is $84 million.
Nuclear Decommissioning Funding and Liability. As of June 30, 2021, the Electric Utility has set aside $48,647 in cash investments with the trustee and $13,838 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, 2021, the Electric Utility has paid to date $36,398 in decommissioning obligations, which have been reimbursed by the trust funds.
As of June 30, 2021 and 2020, decommissioning liability balance was $50,896 and $55,708, respectively, with a portion reflected as current liabilities payable from restricted assets. Due to adequate funding in the liability, 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 Balance Balance Due
As of As of As of Within
6/30/2019 Additions Reductions 6/30/2020 Additions Reductions 6/30/2021 One Year Nuclear decommissioning
liability 58,199 $ 1,350 $ (3,841)$ 55,708 6 2 8 (5,440) 50,896 7 , 2 5 4 NN OO TT EE 1100 .. JJOO IINN TT LLYY -- OO WWNN EEDD UU TTII LLII TT YY PP RROO JJ EE CCTT SS –– SSOO NN GGSS (( CCOO NN TT II NNUU EE DD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
63 NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS The Electric Utility has entered into 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 coal-fueled generating station, known as Intermountain Power Project (IPP), located in central Utah. 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 Intermountain Power Project 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 has 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:
NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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.
The outstanding debts associated with the take-or-pay obligations have fixed interest rates which range from 2.295 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.
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, 2021 and 2020, are as follows (in thousands):
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 the California’s high voltage transmission grid are charged for, and the Electric Utility receives 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
IPA SCPPA TOTAL
Debt Service
Payment Intermountain Southern
(in thousands) Power Transmiss ion All
Year Ending June 30, Project System Projects
2022 8,228$ 9,369$ 17,597$
2023 8,064 7,083 15,147
2024 840 7,125 7,965
2025 - 3,261 3,261
2026 - 3,257 3,257
2027-2031 - 6,507 6,507 Total 17,132$ 36,602$ 53,734$
Palo Verde
Intermountain Nuclear Southern Mead- Mead-
Power Generating Transmission Phoenix Adelanto All
FISCAL YEAR Project 1 Station 1 Syste m Tra nsmission Tra nsmission Proje cts 2021 20,648$ 2,951$ 5,126$ 44$ 424$ 29,193 $ 2020 20,156$ 2,870$ 5,533$ 50$ 541$ 29,150 $ NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
65 reimbursement for, transmission revenue requirements, including the costs associated with these three transmission projects.
HOOVER UPRATING PROJECT
The Electric Utility’s 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 extends the Electric Utility’s 30 MW entitlement in the Hoover project an additional 50 years. The IA is a supplemental agreement to the ESC that establishes administrative, budgetary and project oversight by creating project committees and process for decision making 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 June 10, 2021, the Act limits liability from third-party claims to approximately $13.5 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 $20.5 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 $1.3 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 has met the procurement requirements of SBX1-2 for CP1 (2011-2013) and CP2 (2014-2016). 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 2020, renewable resources provided 42 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 must 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 NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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.
Long-term renewable PPAs and PSAs in operation (dollars in thousands):
1 All 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.
Long-term renewable PPAs with expected delivery:
1 All 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.
2 Represents solar capacity only; battery capacity is 11 MW and 4-hour duration.
Estim a te d
Maximum Contract Annual Cost
Supplier Type Contract 1 Expiration For 2021
Wintec Energy, Ltd. Wind 1.3 MW 2/19/2024 150$
WKN Wagner Wind 6.0 MW 12/22/2032 1,318
Terraform Power - AP North Lake Photovoltaic 20.0 MW 8/11/2040 4,833 Dominion - Columbia II Photovoltaic 11.1 MW 12/22/2034 2,313 GlidePath Power Solutions - GPS Cabazon Wind LLC Wind 39.0 MW 1/1/2025 4,299 Capital Dynamics - Kingbird Solar B, LLC Photovoltaic 14.0 MW 12/31/2036 2,867 FTP Solar
sPower - Summer Solar Photovoltaic 10.0 MW 12/31/2041 1,748 sPower - Antelope Big Sky Ranch Photovoltaic 10.0 MW 12/31/2041 1,748 sPower - Antelope DSR 1 Solar Photovoltaic 25.0 MW 12/19/2036 3,825 Capital Dynamics - Tequesquite Landfill Solar Photovoltaic 7.3 MW 12/31/2040 1,402 American Renewable Power-Loyalton Biomass 0.8 MW 4/19/2023 615 Roseburg Forest Products Biomass 0.5 MW 2/16/2026 179
CalEnergy - Salton Sea Portfolio Geothermal 86.0 MW 12/31/2039 54,798 Atlantica - Coso Geothermal Geothermal 10.0 MW 12/31/2042 2,698 Total 241.0 MW 82,793$
Energy
Delivery Contract
Maximum Expected No Later Term
Supplier Type Contract 1 Delivery Than In Years
Avangrid Renewable - Camino Solar plus Storage Hybrid (Solar & Battery) 44.0 MW 2 Delayed 10/31/2022 15 Atlantica - Coso Geothermal Geothermal 20.0 MW 1/1/2027 1/1/2027 15 Total 64.0 MW
NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
67 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, which increases 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 has been 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, 2021 and 2020, the Electric Utility’s prepayment of future contractual obligations was $13,615 and $14,245, 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, 2021 and 2020, the Electric Utility has recorded $630 and $315, 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.
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 NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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 PSAs with SCPPA for an 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 Projects, with 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.
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.
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.
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.
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% share of the output of the project through SCPPA, 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 became commercially operational 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.
NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
69 On December 18, 2019, the Electric Utility entered into a 15-year PPA with Camino Solar, LLC for 44 MW of solar photovoltaic energy, battery energy storage, associated environmental attributes and capacity rights. The Camino Solar plus Battery Energy Storage Project will generate approximately 147,000 MWh of renewable energy per year. The all-in price for energy, capacity and environmental attributes of the solar is $27.70 per MWh, over the term of the agreement. The Battery Energy Storage capacity of the facility is 11 MW with a minimum four-hour duration. The Battery Energy Storage Capacity price of the facility is $6.48 per kilowatt-month. The project was expected to become commercially operational May 1, 2022, but no later than October 31, 2022. However, the project has encountered significant delays and is no longer expected to be commercially operational by that time. The Utility will be receiving liquidated damages as a result.
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 will begin delivering 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% 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 became commercially operational 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. SB 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, 2021 and 2020, the Electric Utility received $8,251 and $6,433, 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 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 $14,555 and $16,815 as of June 30, 2021 and 2020, 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 $971 as of June 30, 2021 and 2020, and is recorded as inventory in the Statements of Net Position.
NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
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 is was the State’s goal to reduce GHG emissions to 40% below 1990 levels by the year 2020. Like 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 small “start-up” contribution from proceeds is 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, 2021 and 2020, the Electric Utility’s proceeds from the sale of LCFS credits was $1,166 and $1,623, 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 projects that support the Electric Utility’s customers who are existing and future electric vehicle owners.
Qualifying projects as of June 30, 2021 is approximately $440. The balance in the Regulatory Requirement reserve as of June 30, 2021 and 2020 was $2,368 and $1,623, respectively.
CONSTRUCTION COMMITMENTS
As of June 30, 2021, the Electric Utility had commitments (encumbrances) of approximately $22,799 with respect to unfinished capital projects, of which $13,694 is expected to be funded by unrestricted cash reserves, $8,103 to be funded by bonds, and $1,002 to be funded by restricted cash reserves.
FORWARD PURCHASE/SALE AGREEMENTS
In order to meet summer peaking requirements, the Electric Utility may contract on a monthly or quarterly basis, for the purchase or sale of natural gas, electricity and/or capacity products on a short-term horizon.
As of June 30, 2021, the Electric Utility has net commitments for fiscal year 2022 and thereafter, of approximately $11,707, with a market value of $16,749.
NN OO TT EE 1111 .. CCOO MM MMII TT MM EE NN TT SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
71 NN OO TT EE 1122 .. LLIITT II GG AA TT II OO NN
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.
NN OO TT EE 1133 .. SSUU BB SS EEQQ UU EENN TT EE VV EENN TT
PARADA II CLASS ACTION LAWSUIT
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, 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 has set a hearing for February 24, 2021, to set a briefing schedule for determining appropriate remedies /damages in the case. The City expects the second phase of the trial relating to plaintiffs available remedies to occur in the second quarter of 2021. However, due to the impact of the Coronavirus on the Courts, the exact timing of the completion of the trial is uncertain at this time.
The ruling by the Court in Parada II will 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 may be 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 has not issued 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 estimates 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. Currently, petitioners have sought monetary relief solely from the Electric System. However, the City can make no assurance that the City’s General Fund may not be held liable for all or a portion of any refund or other remedy the Court ultimately orders. The City believes that all or a portion of any refund, if owed, could be paid from rate payer revenues in the Electric Fund and that any judgment would likely be allowed by the Court to be paid over a multi-year period. If the electric rates attributable to the General Fund transfer are determined to be invalid or are otherwise repealed and replaced by the City, the City could seek voter approval for the General Fund transfer like it did for the Water Fund. The City has a variety of revenue sources and expense reductions available to it to address any future budget deficits caused by the potential loss of the General Fund transfer, including but not limited to the use of Measure Z revenues.
NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC
On May 17, 2021, the City and the Paradas entered into a conditional settlement agreement. This settlement is 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 have stayed the lawsuit until certification of the results of the Ballot Measure. If voters approve the Ballot Measure, the City will 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 do not approve the Ballot Measure, this litigation will then resume.
On or about September 16, 2021, a petition for writ of mandate entitled Petitioner Riversiders Against Increased Taxes v. City of Riverside, et al. 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 this 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 initial report from the County Registrar of Voters, as of November 3, 2021, is that Measure C was approved by voters. However, the election results have not yet been certified by the City, as noted above, and the Parada lawsuit continues to be stayed pending certification of the results.
NN OO TT EE 1133 .. SSUU BB SS EEQQ UU EENN TT EEVV EENN TT (( CCOO NN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: ELECTRIC73
FISCAL YEAR 2020/21 2019/20 2018/19 2017/18 2016/17
POWER SUPPLY MEGAWATT-HOURS (MWH)
Nuclear
Palo Verde 99,800 100,900 100,200 102,900 102,400
Coal
Intermountain Power 539,200 551,300 677,900 627,100 619,500 Hoover (Hydro) 30,600 27,000 28,600 29,000 28,400
Gas
Springs 1,800 700 400 700 500
RERC 83,800 68,200 93,900 89,600 84,300
Clearwater 9,800 8,600 13,700 24,200 25,900
Renewable Resources1 1,029,300 922,800 835,500 790,100 669,900 Market Purchases 468,000 558,500 511,500 633,500 770,500 Exchanges In 0 0 0 0 0
Exchanges Out 0 0 0 0 0
Total 2,262,300 2,238,000 2,261,700 2,297,100 2,301,400 System peak megawatt (MW) 630.3 587.2 610.9 640.3 581.7
ELECTRIC USE
Number of meters as of year end
Residential 99,226 98,930 98,322 97,531 97,372
Commercial 11,471 11,253 11,219 11,181 11,016
Industrial 962 926 888 854 833
Other 52 52 51 53 53
Total 111,711 111,161 110,480 109,619 109,274
Millions of kilowatt-hours (kWh) sales
Residential 783 723 722 727 730
Commercial 405 417 434 447 448
Industrial 916 956 973 999 996
Other 18 18 21 22 23
Subtotal 2,122 2,114 2,150 2,195 2,197
Wholesale2 0 1 0 0 1
Total 2,122 2,115 2,150 2,195 2,198
Fiscal years 17/18 and 16/17 have each been reduced by 8,100 mWh.
ELECTRIC FACTS
Average annual kWh
per residential customer 7,907 7,322 7,375 7,455 7,519
Average price (cents/kWh)
per residential customer $17.03 $16.77 $16.11 $15.91 $16.12 Debt service coverage ratio (DSC)4,5,6 1.99 2.62 2.24 2.73 2.95 Operating income as a percent 9.6% 12.1% 11.4% 15.3% 20.2% of operating revenues
Employees7 468 466 475 489 472
4Interest expense used to calculate DSC is net of federal subsidy on Build America Bonds. 7Approved positions .
1As of June 30, 2019, Solar PV included in the Renewable Resources has been restated to include only CEC certified renewables. 2 For fiscal years 17/18, 18/19, and 20/21, wholesale kWh was less than 1 million kWh. 5Does not include GASB 68 - Accounting and Financial Reporting for Pension non-cash adjustments of $9,682, $3,364, ($1,323), $9,056, and ($248) for fiscal years 20/21 through 16/17, respectively.
6Does not include GASB 75 - Accounting and Financial Reporting for Post-employment Benefits Other Than Pensions non-cash adjustments of $183, $490, $300, and $697 for fiscal years 20/21 through 17/18, respectively.
EELLEECCTTRRIICC UUTTIILLIITTYY::
KKEEYY HHIISSTTOORRIICCAALL OOPPEERRAATTIINNGG DDAATTAA KEY HISTORICAL OPERATING DATA: ELECTRIC
22 00 22 00 //22 00 22 11 EE LLEE CC TTRR II CC RR EE VV EE NN UU EE AA NN DD RR EE SS OO UU RRCC EE SS
EELLEECCTTRRIICC RRAATTEE CCOOMMPPAARRIISSOONN -- 660000 KKWWHH PPEERR MMOONNTTHH ((AASS OOFF JJUUNNEE 3300,, 22002211))
SOURCE OF
REVENUE
Residential Sales 33¢
Industrial Sales 29¢
Commercial Sales 17¢
Transmission Revenue 9¢
Other Revenue 6¢
Use of Reserves 3¢
Public Benefit Programs 2¢
Other Sales 1¢
Investment Income (less than 1¢)
DISTRIBUTION OF
REVENUE
Production 41¢
Distribution 16¢
Transmission 15¢
Debt Service 12¢
Transfers to the City's General Fund* 10¢
Additions & Replacements to the System 4¢
Public Benefit Programs 2¢
Unamortized Purchased Power (less than 1¢)
ENERGY
RESOURCES**
Renewables 42%
Coal 25%
Market Purchases 22%
Nuclear 5%
Gas 5%
Hydropower 1%
$210 $147
San Diego Gas & Electric
Southern California
Edison
Riverside Public
Utilities
$0
$25
$50
$75
$100
$125
$150
$175
$200
$225
119% Higher 53% Higher $96
*Based on transfer of 11.5% of fiscal year
2019/2020 gross operating revenues including
adjustments.
**Energy Resources are based on calendar year 2020
as filed with the California Energy Commission
KEY HISTORICAL OPERATING DATA: ELECTRIC75
EE LL EE CC TT RR II CC KKEE YY OO PPEE RR AA TTII NN GG II NN DD II CCAA TTOORR SS
$39.2
$40.1
$39.9
$39.6
$39.9
2017
2018
2019
2020
2021
General Fund Transfer (In Millions)
1 1 As of June 30, 2019, Solar PV included in the Renewable Resources has been restated to include only CEC certified renewables.
Fiscal years 17/18 and 16/17 have each been reduced by 8,100 mWh. 109,274
109,619
110,480
111,161
111,711
2017
2018
2019
2020
2021
Number of Meters At Year End
$366.1
$363.8
$362.7
$367.1
$372.1
2017
2018
2019
2020
2021
Total Operating Revenue (In Millions)
2,301
2,297
2,262
2,238
2,262
2017
2018
2019
2020
2021
Production (In Million Kilowatt-Hours)1
581.7
640.3
610.9
587.2
630.3
2017
2018
2019
2020
2021
Peak Day Demand (In Megawatts)
KEY HISTORICAL OPERATING DATA: ELECTRIC
EE LL EE CC TT RR II CC FF AA CC TTSS AA NN DD SS YY SS TTEE MM DD AA TT AA
Established ................................................................................................................ 1895
Service Area Population ....................................................................................... 324,243
City Service Area Size (square miles) ........................................................................ 81.5
System Data
Transmission Lines (circuit miles) ........................................................................ 99.2 Distribution Lines (circuit miles) ......................................................................... 1,351 Number of Substations ........................................................................................... 16 2020-21 Peak Day (megawatts) ........................................................................... 630 Highest Single Hourly Use:
08/18/2020, 2pm, 102.0 degrees
Historical Peak (megawatts) ................................................................................. 640 Highest Single Hourly Use:
08/31/2017, 3pm, 89.9 degrees
Bond Ratings
Fitch Ratings ......................................................................................................... AA- Standard & Poor’s ................................................................................................ AA-
KEY HISTORICAL OPERATING DATA: ELECTRIC77
WATEROUR
RIVERSIDE PUBLIC UTILITIES
INDEPENDENT AUDITORS’ REPORT
To the Honorable City Council and Board of Public Utilities City of Riverside, California
Report on the Financial Statements
Opinions
We have audited the accompanying financial statements of the Water Utility Enterprise Fund (Water Utility) of the City of Riverside, California, (the City) as of and for the years ended June 30, 2021 and 2020, and the related notes to the financial statements, which collectively comprise the Water Utility’s financial statements as listed in the table of contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Water Utility Enterprise Fund of the City of Riverside, as of June 30, 2021 and 2020, and the respective changes in financial position and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matters
As discussed in Note 1, the financial statements present only the Water Utility Enterpri se Fund of the City of Riverside and do not purport to, and do not present fairly t he financial position of the City as of June 30, 2021 and 2020, the changes in its financial position, or, where applicable, its cash flows for the years then ended in accordance with accounting principles gener ally accepted in the United States of America. Our opinion is not modified with respect to this matter.
Basis for Opinions
We conducted our audit in accordance with auditing standards ge nerally accepted in the United States of America (GAAS) and the standards applicable to financial aud its contained in Government Auditing Standards, issued by the Comptroller General of the United States. Our r esponsibilities under those standards are further described in the Auditor’s Responsibiliti es for the Audit of the Financial Statements section of our report. We are required to be independent of the Water Utility and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presenta tion of these financial statements in accordance with accounting prin ciples generally accepted in the United States of America; and for the design, implementation, and maintenance of internal control rel evant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Water Utility’s ability to continue as a going concern for twelve months beyond the date of the financial statements.
203 N. Brea Blvd., Suite 203
Brea, CA 92821 Lance, Soll & Lunghard, LLP Phone: 714.672.0022
To the Honorable City Council and Board of Public Utilities City of Riverside, California
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with t he GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusi on, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users made on the basis of these financial statements.
In performing an audit in accordance with GAAS, we:
Exercise professional judgment and maintain professional skept icism throughout the audit. Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures respons ible to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
Obtain an understanding of internal control relevant to the au dit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Water Utility’s internal control. Accordingly, no such opinion is expressed. Evaluate the appropriateness of accounting policies used and t he reasonableness of significant accounting estimates made by management, as well as evaluate th e overall presentation of the financial statements.
Conclude whether, in our judgment, there are conditions or eve nts, considered in the aggregate, that raise substantial doubt about the Water Utility’s ability to continue as a going concern for a reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
Other Reporting Responsibilities
Required Supplementary Information
Accounting principles generally accepted in the United States o f America require that the management’s discussion and analysis as listed in the table of content, be p resented to supplement the basic financial statements. Such information is the responsibility of managemen t and, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board, who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied c ertain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about th e methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements.
We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
To the Honorable City Council and Board of Public Utilities City of Riverside, California
Other Information
Our audit was conducted for the purpose of forming opinions on the financial statements of the Water Utility’s financial statem ents. The key historical operat ing data are presented for purposes of additional analysis and are not a required part of the basic financial statements.
The key historical operating data have not been subjected to th e auditing procedures applied in the audit of the basic financial statements and, accordingly, we do not express an opinion or provide any assurance on them.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards , we have also issued our report dated November 9, 2021 on our consideration of the City’s internal co ntrol over financial reporting and on our tests of its compliance with certain provisions of laws, regula tions, contracts, and grant agreements and other matters. The purpose of t hat report is solely to describe the scope of our testing of Internal control over financial reporting and compliance and th e results of that testing, and not to provide an opinion on the effectiveness of the City’s internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards in considering the City’s internal control over financial reporting and compliance.
Brea, California
November 9, 2021
Retail sales, net of uncollectibles/recovery, were $70,847 and $61,683 for the fiscal years ended June 30, 2021 and 2020, respectively. The increase in sales was primarily due to the rate plan increase and increase in consumption.
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 ($1,107) and $1,046 in June 30, 2021 and 2020, respectively. Operating expense reflects a non-cash postemployment benefits other than pensions (OPEB) accounting standard adjustment, which will continue to fluctuate based on yearly actuarial information provided by CalPERS. The adjustment was $73 and $197 in June 30, 2021 and 2020, respectively. 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 ($534) and $575 in June 30, 2021 and 2020, respectively.
OO VV EE RRVV IIEE WW OOFF TT HH EE FF II NNAA NN CC IIAA LL SS TTAA TT EEMM EENN TT SS 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.
WWAATTEERR UUTTIILLIITTYY::
MMAANNAAGGEEMMEENNTT’’SS DDIISSCCUUSSSSIIOONN AANNDD AANNAALLYYSSIISS 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 2020-21 financial report for the period ended June 30, 2021 and 2020 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 96 of this report. All amounts, unless otherwise indicated, are expressed in thousands of dollars.
F INA N CIA L H I GH L I GH T S
MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
OO VV EE RRVV IIEE WW OOFF TT HH EE FF II NNAA NN CC IIAA LL SS TTAA TT EEMM EENN TT SS (( CCOO NN TT IINN UU EEDD )) 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 Water Utility’s financial statements. The Notes to the Financial Statements can be found on pages 100 to 132 of this report.
CC OO RROO NNAA VVII RRUU SS DD IISS EEAA SS EE 22 00 1199 (( CCOO VV IIDD -- 11 99)) In December 2019, an outbreak of a novel strain of coronavirus (COVID-19) spread to a number of countries, including the United States (U.S.). On March 11, 2020, the World Health Organization characterized COVID-19 as a pandemic. In addition, several states in the U.S., including California, declared a state of emergency. Potential impacts to the City future tax revenues include disruptions or restrictions on current employees’ ability to work. Any of the foregoing could negatively impact revenues and the City currently cannot anticipate all of the ways in which this health epidemic, COVID-19, could adversely impact our government agency. Potential impacts will continue to be monitored.
C O R O N A V I R U S A I D , R E L I E F , A N D E C O N O M I C S E C U R I T Y A C T ( C A R E S ) On March 27, 2020, President Trump signed the Coronavirus Aid, Relief, and Economic Security Act into law to provide emergency appropriations during the Coronavirus pandemic. The CARES Act represented the third package of assistance from the federal government, providing $2.2 trillion in economic relief to individuals, families, businesses, and nonprofit organizations. Funding for governments was also included through the creation of the Coronavirus Relief Fund, which allocated $150 billion to various State, local and Tribal governments. The Coronavirus Relief Fund (CRF) was distributed to State, local and Tribal governments based on relative population. Local governments with a population of 500,000 or more were eligible to receive a direct allocation from the CRF. Given the population threshold, the City was not eligible to receive a direct allocation.
Throughout the COVID-19 pandemic, the Big City Mayors (BCM) met with federal and state elected officials to advocate for much needed assistance. As part of this effort, the BCM engaged the State’s legislative leaders and Governor to solicit support for the creation of a dedicated funding opportunity for the seven cities (Long Beach, Oakland, Bakersfield, Anaheim, Santa Ana, Riverside, and Stockton) of the coalition that did not receive a direct allocation from the CRF due to population size. This targeted advocacy effort resulted in the inclusion of a specific $225 million set-aside for these seven cities as part of the State budget with the City of Riverside receiving an allocation of approximately $28 million. The CARES Act spending plan was approved by City Council on August 4, 2020 and on July 13, 2021, a final CARES Act expenditure report was presented to City Council.
A M E R I C A N R E S C U E P L A N A C T ( A R P A )
On March 11, 2021, President Biden passed the $1.9 trillion American Rescue Plan Act (ARPA) that is sending checks to families and offering small business support to drive up demand and counter the country’s high unemployment. The ARPA established Coronavirus State Fiscal Recovery Fund and Coronavirus Local Fiscal Recovery Fund, which provides a combined $350 billion in assistance to eligible state, local, territorial, and Tribal governments to assist in the economic and health recovery by providing resources to address impacts resulting from the crisis. The City will receive one-time fund of approximately $73.5 million from ARPA with the first installment of $36.7 million received in June 2021 and the remainder will be received in June 2022.
MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
85 As of 2021 City and the Water Utility are continuing to monitor and assess the effects of the COVID-19 pandemic on our government agency and the public. The City and the Water Utility are pursuing all available of programs to assists with impacts of the pandemic. For additional information, refer to the ACFR.
WW AA TT EE RR UU TT II LLIITT YY FF II NNAA NN CCII AA LL AA NNAA LLYY SS IISS
CONDENSED STATEMENTS OF NET POSITION
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
2021 compared to 2020 The Water Utility’s total assets and deferred outflows of resources were $607,047, reflecting a decrease of $22,589 (3.6%) primarily due to the following:
Current and other assets, comprised of restricted and unrestricted assets, had a net increase of $695, primarily due to an increase of $4,441 in accounts receivable, primarily due to COVID-19 impacts, and an increase of $4,969 in unrestricted cash and cash equivalents. The increase is offset by a decrease of $8,327 in restricted cash and cash equivalents, primarily due to the use of restricted bond proceeds. Capital assets increased by $151 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 decreased by $23,435 primarily due to a decrease of $21,698 in deferred outflows related to pension as a result of payment outflow of the 2020 Pension Obligation Bond Series A, and a decrease of $314 in loss on refunding due to the amortization. 2020 compared to 2019 Total assets and deferred outflows of resources were $629,636, reflecting an increase of $11,876 (1.9%) over prior year. Current and other assets, comprised of restricted and 2021 2020 2019
Current and other assets 92,883$ 92,188$ 105,623$ Capital assets 499,636 499,485 495,351
Deferred outflows of resources 14,528 37,963 16,786 Total assets and deferred outflows of resources 607,047 629,636 617,760 Long-term debt outstanding 250,728 261,353 250,026 Other liabilities 47,195 63,847 59,172 Deferred inflows of resources 764 3,801 5,861 Total liabilities and deferred inflows of resources 298,687 329,001 315,059 Net investment in capital assets 291,541 291,659 292,394 Restricted 10,599 10,186 8,949
Unrestricted 6,220 (1,210) 1,358 Total net position 308,360$ 300,635$ 302,701$ CC OO RROO NNAA VVII RRUU SS DD IISS EEAA SS EE 22 00 1199 (( CCOO VV IIDD -- 11 99)) (( CCOO NNTT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
unrestricted assets, had a net decrease of $13,435, primarily due to the use of $11,648 of restricted bond proceeds and $3,068 of unrestricted cash to fund capital projects. The net decrease was offset by an increase of $1,329 in accounts receivable. Capital assets increased by $4,134 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 increased by $21,177 primarily due to an increase of $21,487 in deferred outflows related to pension for the 2020 Pension Obligation Bond Series A issue, deferred outflow related to other postemployment benefits (OPEB) due to the difference between projected and actual earnings on plan investments and changes in derivative values. The increase is primarily offset by a decrease of $310 in loss on refunding due to the amortization.
LIABILITIES AND DEFERRED INFLOWS OF RESOURCES
2021 compared to 2020 The Water Utility’s total liabilities and deferred inflows of resources were $298,687, a decrease of $30,314 (9.2%) primarily due to the following:
Long-term debt outstanding decreased by $10,625 primarily due to a decrease in revenue bonds payable, note payable and leases payable. Additional debt information can be found in the “Capital Assets and Debt Administration” section.
Other liabilities decreased by $16,652 primarily due to decrease of $19,637 in net pension liability, a decrease of $2,091 in derivative instruments due to a decrease in the fair market value of interest rate swaps, offset by an increase of $2,305 in unearned revenues with the City of Corona, an increase in accounts payable and other accruals of $874, and an increase of $714 in the current portion of long- term obligations. Additional information on note payable can be found in Note 4 of the accompanying financial statements.
Deferred inflows of decreased by $3,037 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. 2020 compared to 2019 Total liabilities and deferred inflows of resources were $329,001, reflecting an increase of $13,942 (4.4%). Long-term debt outstanding increased by $11,327, primarily due to the issuance of the 2020 Pension Obligation Bond Series A, offset by a decrease in revenue bonds payable, note payable and leases payable. Other liabilities increased by $4,675 primarily due to an increase of $1,103 in net pension liability, an increase of $2,517 in derivative instruments due to an increase in the fair market value of interest rate swaps, and an increase of $872 in the current portion of long-term obligations.
Deferred inflows of decreased by $2,060 primarily due to pension related adjustments.
NET POSITION
2021 compared to 2020 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 $308,360, an increase of $7,725 (2.6%). The largest portion of the Water Utility’s total net position, which is its investment in capital assets of $291,541 (94.5%), had a decrease of $118 and is consistent with prior year. Additional capital asset information can be found in the “Capital Assets and Debt Administration” section. The restricted portion of net position totaled $10,599 (3.4%), reflecting an increase of $413 and represents 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.
WW AA TT EE RR UU TT II LLIITT YY FF II NNAA NN CCII AA LL AANN AA LLYYSS IISS (( CCOO NN TT II NN UU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
87 The unrestricted portion of net position totaled $6,220 (2%), an increase of $7,430 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. 2020 compared to 2019 Total net position decreased by $2,066 (0.7%) to $300,635. The investment in capital assets of $291,659, had a decrease of $735 from prior year. The restricted portion of net position totaled $10,186, reflecting an increase of $1,237, primarily due to an increase in restricted debt service reserve related to the principal payment increase of the 2019A Water Revenue Refunding Bonds and an increase in Water Conservation Programs equity due to a decrease in net pension liability. The unrestricted portion of net position totaled ($1,210), a decrease of $2,568 from prior year, primarily attributable to the use of unrestricted cash and cash equivalent to fund capital projects.
CONDENSED STATEMENTS OF CHANGES IN NET POSITION
2021 2020 2019
Revenues:
Retail sales, net 70,847$ 61,683$ 57,605$ Other revenues 12,532 10,862 10,530
Investment (loss) income (1) 2,073 2,044
Capital contributions 3,062 3,129 3,119
Total revenues 86,440 77,747 73,298
Expenses:
Operations and maintenance 39,143 41,845 39,217
Purchased energy 6,523 5,583 5,748
Depreciation 16,346 16,010 15,450
Interest expenses and fiscal charges 9,731 9,857 10,412 Total expenses 71,743 73,295 70,827
Transfers:
Transfers to the City's general fund (6,972) (6,518) (6,584) Total transfers (6,972) (6,518) (6,584)
Changes in net position 7,725 (2,066) (4,113)
Net position, July 1, as previously reported 300,635 302,701 305,078 Less: Cumulative effect of change in accounting principle (1) - - 1,736 Net position, July 1, as restated 300,635 302,701 306,814 Net position, June 30 308,360$ 300,635$ 302,701$ (1) For the restatement of pension allocation, GASB Statement No. 68, for the year ended June 30, 2019.
WW AA TT EE RR UU TT II LLIITT YY FF II NNAA NN CCII AA LL AANN AA LLYYSS IISS (( CCOO NN TT II NN UU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
REVENUES BY SOURCES
2021 compared to 2020 The Water Utility’s total revenues of $86,440 increased by $8,693 (11.2%) primarily due to the following changes:
Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $70,847, an increase of $9,164 (14.9%) 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 and a 10.32% increase in consumption.
Other revenues of $12,532 increased by $1,670 (15.4%), primarily due to an increase in water wholesale revenue from Western Municipal Water District (WMWD). Capital contribution of $3,062 decreased by $67 (2.1%) and is consistent with prior year. Investment income (loss) of ($1) decreased by $2,074 (100%) due to a lower overall interest rate in the current fiscal year and the accounting standard for fair market value adjustment of investments. 2020 compared to 2019 The Water Utility’s total revenues of $77,747 increased by $4,449 (6.1%) primarily due to the following changes:
Retail sales (residential, commercial, industrial, and others), net of uncollectibles/recovery, totaled $61,683, an increase of $4,078 (7.1%) from prior fiscal year. Retail sales continue to be the primary revenue source for the Water Utility. The increase was due to the rate increase and a 1.5% increase in consumption.
Other revenues of $10,862 increased by $332 (3.2%) due to an increase in water conveyance revenue from Western Municipal Water District (WMWD).
June 30, 2021
Retail Sales 82%
Other 14%
Capital Contributions 4%
Investment Income (Loss) <1%
June 30, 2020
Retail Sales 79%
Other 14%
Capital Contributions 4%
Investment Income 3%
WW AA TT EE RR UU TT II LLIITT YY FF II NNAA NN CCII AA LL AANN AA LLYYSS IISS (( CCOO NN TT II NN UU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
89 Capital contribution of $3,129 increased by $10 (0.3%) and is consistent with prior year. Investment income of $2,073 increased by $29 (1%) and is consistent with prior year.
EXPENSES BY SOURCES
2021 compared to 2020 The Water Utility’s total expenses, excluding general fund transfer, were $71,743, a decrease of $1,552 (2.1%). The decrease was primarily due to the following:
Operations and maintenance expenses of $39,143 decreased by $2,702 (6.5%), mainly due to a non-cash pension adjustment of ($1,107) compared to prior year non-cash pension adjustment of $1,046 as a result of pension accounting standards.
Purchased energy and water expenses of $6,523 increased by $940 (16.8%) from prior year, primarily attributable to an increase in the electric costs.
2020 compared to 2019 The Water Utility’s total expenses, excluding general fund transfer, were $73,295, an increase of $2,468 (3.5%). The increase was primarily due to the following:
Operations and maintenance expenses of $41,485 increased by $2,628 (6.7%), mainly due to a non-cash pension adjustment of $1,046 compared to prior year non-cash pension adjustment of ($482) as a result of pension accounting standards.
Purchased energy and water expenses of $5,583 decreased by $165 (2.9%) from prior year, primarily attributable to a decrease in the electric costs.
June 30, 2021
Operations 42%
Depreciation 21%
Interest Expense 12%
Contributions to the City's General Fund 9%
Maintenance 8%
Purchased Energy 8%
June 30, 2020
Operations 46%
Depreciation 20%
Interest Expense 12%
Contributions to the City's General Fund 8%
Maintenance 7%
Purchased Energy 7%
WW AA TT EE RR UU TT II LLIITT YY FF II NNAA NN CCII AA LL AANN AA LLYYSS IISS (( CCOO NN TT II NN UU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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 $6,972 and $6,518 for 2021 and 2020, respectively based on the gross operating revenue provisions in the City’s Charter.
CC AA PP II TTAA LL AA SS SS EETT SS AA NN DD DD EEBB TT AA DD MMII NN II SSTT RR AA TTII OO NN
CAPITAL ASSETS
The Water Utility’s investment in capital assets includes investments in source of supply, pumping, treatment, transmission and distribution facilities, land, intangibles, and construction in progress, 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:
2021 compared to 2020 The Water Utility’s investment in capital assets, net of accumulated depreciation, was $499,636, an increase of $151 (0.03%) from prior year. The increase resulted primarily from the increase in construction in progress. The Water Utility's significant capital projects include the following:
$7,700 in distribution pipelines, such as main replacements, distribution system facilities replacement and system expansion.
$1,211 in well projects, such as potable irrigation well replacements and facility rehabilitation. $2,345 in distribution facilities, such as pump station replacements and meters. 2020 compared to 2019 The Water Utility’s investment in capital assets, net of accumulated depreciation, was $499,485, an increase of $4,134 (0.8%) from prior year. The increase resulted primarily from the increase in construction in progress. Significant capital projects included $10,110 in distribution pipelines, $3,461 in well projects, $2,277 in distribution facilities and $630 in donated transmission and distribution services.
Additional information regarding capital assets can be found in Note 3 of the accompanying financial statements.
2021 2020 2019
Source of supply 54,424$ 53,648$ 48,434$ Pumping 20,146 18,726 19,213
Treatment 27,122 28,284 29,523
Transmission and distribution 332,467 339,018 341,198 General 3,032 3,486 3,944
Land 20,841 20,841 20,840
Intangible 11,469 12,141 12,807 Construction in progress 30,135 23,341 19,392 Total capital assets 499,636$ 499,485$ 495,351$
WW AA TT EE RR UU TT II LLIITT YY FF II NNAA NN CCII AA LL AANN AA LLYYSS IISS (( CCOO NN TT II NN UU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
91 DEBT ADMINISTRATION
The following table summarizes outstanding long-term debt as of June 30:
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 2.25, 1.80, and 1.68 at June 30, 2021, 2020, and 2019, respectively. The debt is backed by the revenues of the Water Utility. Debt service coverage ratio increased at June 30, 2021 due to positive operating results. For additional information, see Note 4 of the accompanying financial statements and the Key Historical Operating Data section. 2021 compared to 2020 The Water Utility’s long-term debt decreased by $10,625 (4.1%) to $250,728 as a result of the current year principal payments and amortization of bond premiums.
2020 compared to 2019 Long-term debt increased by $11,327 (4.5%) to $261,353 as a result of issuance of the 2020 Pension Obligation Bond Series A, offset by current year principal payments and amortization of bond premiums.
Additional information on the Water Utility’s long-term debt can be found in Note 4 of the accompanying financial statements.
CREDIT RATINGS
The Water Utility maintains credit ratings of “AAA”, “AA+” and “Aa2” from S&P Global Ratings (S&P), Fitch Ratings (Fitch) and Moody’s, respectively. These ratings reflect the Water Utility’s strong financial performance, advantageous water supply, investments in infrastructure and rate competitiveness, among many other factors.
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS Utilities are faced with ongoing regulatory and legislative mandates enacted at the federal and state level that will have significant impacts on the operations of the Water Utility.
The State of California has experienced unprecedented drought conditions in recent years resulting in severe impacts to California’s water supplies and its ability to meet all of the demands for water in the State.
The Water Utility is very fortunate as a water provider in California in that the Water Utility owns, operates and maintains its own water supply and is not typically dependent on imported water from outside sources.
The Water Utility currently has sufficient water supplies to meet customer needs even during severe drought conditions; however, the aquifers the Water Utility draws from are experiencing historic low levels. The Water Utility has responded by continuing to offer a wide variety of water conservation programs for its customers in an effort to conserve its water resources. 2021 2020 2019
Revenue bonds 198,830$ 205,165$ 210,685$ Unamortized bond premium 18,476 19,714 20,954 Pension obligation bonds 22,363 23,035 3,028 Contracts payable 1,067 1,019 937 Leased purchases 1,445 1,666 1,884
Note payable 18,138 19,524 20,323 Less: Current portion of outstanding debt (9,591) (8,770) (7,785) Total 250,728$ 261,353$ 250,026$
CC AA PP II TTAA LL AA SS SS EETT SS AA NN DD DD EEBB TT AA DD MMIINN IISS TT RR AATT II OO NN (( CCOO NN TT II NNUU EE DD)) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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 residents 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 water conservation and efficiency programs have assisted the residents and business to save 58,283,789 gallons of water for the period from July 2020 to June 2021.
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.
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, the Governor 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 and SB 606, the City must set, meet and report water use objectives for its service area using a water budget-based approach by 2023. In addition, the City must conduct and submit a Water Shortage Contingency Plan and a Drought Risk Assessment every 5 years as part of its Urban Water Management Plan and annual water supply and demand assessment.
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
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
93 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 August 2019, 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 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.
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.
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
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.” 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.”
FIVE-YEAR WATER RATE PLAN
On May 22, 2018, the City Council approved a new five-year Water Rate Plan, which includes system average annual rate increases. The first annual rate increase was effective July 1, 2018 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 increase effective July 1, 2018 was 4.50%, followed by system average rate increases of 5.75% in years two through four, and a system average rate increase of 6.50%, effective July 1, 2022, in the final year of the rate plan. The Water Rate Plan included a redesign of water rates over a five-year period to better align with its cost of serving customers and its revenue requirement. The water rate restructuring was designed to provide financial stability and correct the imbalance of costs versus revenue recovery by increasing fixed cost recovery through monthly service charges to reflect the nature of underlying costs. Pursuant to City Council direction, the first annual review of rates was conducted in February 2020 and the second annual review of rates was conducted in January 2021.
RR EEQQ UU EESS TT SS FF OO RR II NN FF OO RR MM AA TT IIOO NN 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, 3rd floor, Riverside, CA 92501. Additional financial information can also be obtained by visiting www.RiversidePublicUtilities.com.
RR EEGG UU LLAA TTOO RRYY ,, LL EEGG II SS LLAA TT II VV EE FF AA CCTT OO RR SS ,, AANN DD RRAA TT EE SS (( CCOO NN TT IINN UU EEDD )) MANAGEMENT’S DISCUSSION & ANALYSIS: WATER
95 City of Riverside Water Utility
STATEMENTS OF NET POSITION
June 30, June 30,
2021 2020
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 499,636$ 499,485$ Restricted assets:
Cash and cash equivalents at fiscal agent (Note 2) 20,108 28,826 Other non-current assets:
Regulatory assets 934 994
Other long-term assets 3,225 3,525
Total other non-current assets 4,159 4,519 Total non-current assets 523,903 532,830 CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 42,947 37,978 Accounts receivable, less allowance for doubtful accounts 2021 $514; 2020 $559 14,420 9,979 Accrued interest receivable 85 114 Prepaid expenses 238 225
Other current assets 300 300
Total unrestricted current assets 57,990 48,596 Restricted assets:
Cash and cash equivalents (Note 2) 7,435 7,293 Water Conservation Programs - cash and cash equivalents (Note 2) 3,039 2,790 Water Conservation Programs receivable 152 164 Total restricted current assets 10,626 10,247 Total current assets 68,616 58,843
Total assets 592,519 591,673
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 4,921 26,619 Deferred outflow related to other postemployment benefits (Note 7) 871 644 Changes in derivative values 3,442 5,092 Loss on refunding 5,294 5,608
Total deferred outflows of resources 14,528 37,963 Total assets and deferred outflows of resources 607,047$ 629,636$ See accompanying notes to the financial statements
(in thousands)
FINANCIAL STATEMENTS: WATER
SS TT AA TT EEMM EE NNTT SS OO FF NN EE TT PP OO SS IITT II OO NN WWAATTEERR UUTTIILLIITTYY::
FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS
June 30, June 30,
2020 2019
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 499,485$ 495,351$ Restricted assets:
Cash and investments at fiscal agent (Note 2) 28,826 40,474 Other non-current assets:
Regulatory assets 994 1,055
Other long-term assets 3,525 3,825
Total other non-current assets 4,519 4,880 Total non-current assets 532,830 540,705
CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 37,978 41,038 Accounts receivable, less allowance for doubtful accounts 2020 $559; 2019 $170 9,979 8,650
Accrued interest receivable 114 138 Advances to other funds of the City - 139 Prepaid expenses 225 227
Other current assets 300 300
Total unrestricted current assets 48,596 50,492 Restricted assets:
Cash and cash equivalents (Note 2) 7,293 7,233 Water Conservation Programs - cash and cash equivalents (Note 2) 2,790 2,442 Water Conservation Programs receivable 164 102 Total restricted current assets 10,247 9,777 Total current assets 58,843 60,269
Total assets 591,673 600,974
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 26,619 8,115 Deferred outflow related to other postemployment benefits (Note 7) 644 - Changes in derivative values 5,092 2,753 Loss on refunding 5,608 5,918
Total deferred outflows of resources 37,963 16,786 Total assets and deferred outflows of resources 629,636$ 617,760$ See accompanying notes to the financial statements
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF NN EE TT PP OO SS IITT II OO NN WWAATTEERR UUTTIILLIITTYY::
FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS
June 30, June 30,
2020 2019
ASSETS AND DEFERRED OUTFLOWS OF RESOURCES
NON-CURRENT ASSETS:
Utility plant:
Utility plant, net of accumulated depreciation (Note 3) 499,485$ 495,351$ Restricted assets:
Cash and investments at fiscal agent (Note 2) 28,826 40,474 Other non-current assets:
Regulatory assets 994 1,055
Other long-term assets 3,525 3,825
Total other non-current assets 4,519 4,880 Total non-current assets 532,830 540,705
CURRENT ASSETS:
Unrestricted assets:
Cash and cash equivalents (Note 2) 37,978 41,038 Accounts receivable, less allowance for doubtful accounts 2020 $559; 2019 $170 9,979 8,650
Accrued interest receivable 114 138 Advances to other funds of the City - 139 Prepaid expenses 225 227
Other current assets 300 300
Total unrestricted current assets 48,596 50,492 Restricted assets:
Cash and cash equivalents (Note 2) 7,293 7,233 Water Conservation Programs - cash and cash equivalents (Note 2) 2,790 2,442 Water Conservation Programs receivable 164 102 Total restricted current assets 10,247 9,777 Total current assets 58,843 60,269
Total assets 591,673 600,974
DEFERRED OUTFLOWS OF RESOURCES:
Deferred outflows related to pension (Note 6) 26,619 8,115 Deferred outflow related to other postemployment benefits (Note 7) 644 - Changes in derivative values 5,092 2,753 Loss on refunding 5,608 5,918
Total deferred outflows of resources 37,963 16,786 Total assets and deferred outflows of resources 629,636$ 617,760$ See accompanying notes to the financial statements
(in thousands)
City of Riverside Water Utility
STATEMENTS OF NET POSITION
June 30, June 30,
2021 2020
NET POSITION, LIABILITIES, AND DEFERRED INFLOWS OF RESOURCES NET POSITION:
Net investment in capital assets 291,541$ 291,659$ Restricted for:
Debt service (Note 8) 7,435 7,284
Water Conservation Programs 3,164 2,902 Unrestricted 6,220 (1,210)
Total net position 308,360 300,635
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (Note 4) 250,728 261,353 OTHER NON-CURRENT LIABILITIES:
Net other postemployment benefits liability (Note 7) 4,550 4,382 Net pension liability (Note 6) 12,203 31,840 Compensated absences (Note 5) 1,120 549 Derivative instrument (Note 4) 5,683 7,774 Regulatory liability 3,689 3,248
Total other non-current liabilities 27,245 47,793 CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS:
Accrued interest payable 1,408 1,489
Water Conservation Programs payable 28 10 Current portion of long-term obligations (Note 4) 7,942 7,228 Total current liabilities payable from restricted assets 9,378 8,727 CURRENT LIABILITIES:
Accounts payable and other accruals 3,964 3,090 Current portion of long-term obligations (Note 4) 1,649 1,542 Unearned revenue 2,347 42
Customer deposits 1,013 913
Compensated absences (Note 5) 1,599 1,740 Total current liabilities 10,572 7,327
Total liabilities 297,923 325,200
DEFERRED INFLOWS OF RESOURCES:
Deferred inflows related to pension (Note 6) 533 3,702 Deferred inflows related to other postemployment benefits (Note 7) 231 99 Total deferred inflows of resources 764 3,801 Total net position, liabilities and deferred inflows of resources 607,047$ 629,636$ See accompanying notes to the financial statements
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF NN EE TT PP OO SS IITT II OO NN
June 30, June 30,
2020 2019
NET POSITION, LIABILITIES, AND DEFERRED INFLOWS OF RESOURCES NET POSITION:
Net investment in capital assets 291,659$ 292,394$ Restricted for:
Debt service (Note 8) 7,284 6,710
Water Conservation Programs 2,902 2,239
Unrestricted (1,210) 1,358
Total net position 300,635 302,701
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION (Note 4) 261,353 250,026 OTHER NON-CURRENT LIABILITIES:
Net other postemployment benefits liability (Note 7) 4,382 3,524 Net pension liability (Note 6) 31,840 30,737 Compensated absences (Note 5) 549 299
Derivative instrument (Note 4) 7,774 5,257 Regulatory liability 3,248 3,427
Total other non-current liabilities 47,793 43,244 CURRENT LIABILITIES PAYABLE FROM RESTRICTED ASSETS:
Accrued interest payable 1,489 2,733
Water Conservation Programs payable 10 4 Current portion of long-term obligations (Note 4) 7,228 6,356 Total current liabilities payable from restricted assets 8,727 9,093 CURRENT LIABILITIES:
Accounts payable and other accruals 3,090 2,850 Current portion of long-term obligations (Note 4) 1,542 1,429 Unearned revenue 42 39
Customer deposits 913 789
Compensated absences (Note 5) 1,740 1,728 Total current liabilities 7,327 6,835
Total liabilities 325,200 309,198
DEFERRED INFLOWS OF RESOURCES:
Deferred inflows related to pension (Note 6) 3,702 5,744 Deferred inflows related to other postemployment benefits (Note 7) 99 117 Total deferred inflows of resources 3,801 5,861 Total net position, liabilities and deferred inflows of resources 629,636$ 617,760$ See accompanying notes to the financial statements
(in thousands)
FINANCIAL STATEMENTS: WATER
97 City of Riverside Water Utility
STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET POSITION 2021 2020
OPERATING REVENUES:
Residential sales 44,781$ 39,001$
Commercial sales 23,704 21,244
Other sales 2,357 1,885
Water conveyance revenue 2,964 3,255
Water Conservation Programs 1,067 1,023
Other operating revenue 5,379 3,759
Total operating revenues before uncollectibles 80,252 70,167 Estimated uncollectibles, net of bad debt recovery 5 (447) Total operating revenues, net of uncollectibles 80,257 69,720 OPERATING EXPENSES:
Operations 32,037 36,091
Maintenance 6,301 5,394
Purchased energy 6,523 5,583
Water Conservation Programs 805 360
Depreciation 16,346 16,010
Total operating expenses 62,012 63,438
Operating income 18,245 6,282
NON-OPERATING REVENUES (EXPENSES):
Investment (loss) income (1) 2,073
Interest expense and fiscal charges (9,731) (9,857)
Gain on sale of assets 120 69
Other 3,002 2,756
Total non-operating revenues (expenses) (6,610) (4,959) Income before capital contributions and transfers 11,635 1,323 Capital contributions 3,062 3,129
Transfers out - contributions to the City's general fund (6,972) (6,518) Total capital contributions and transfers (3,910) (3,389) Change in net position 7,725 (2,066)
NET POSITION, BEGINNING OF YEAR 300,635 302,701
NET POSITION, END OF YEAR 308,360$ 300,635$
See accompanying notes to the financial statements
(in thousands)
For the Fiscal Year
Ended June 30
SS TT AA TT EEMM EE NNTT SS OO FF RR EE VVEENN UU EESS ,, EE XXPP EE NN SSEE SS AA NN DD CCHH AA NN GG EESS II NN NN EETT
PP OO SSII TT II OONN
2020 2019
OPERATING REVENUES:
Residential sales 39,001$ 35,408$
Commercial sales 21,244 20,539
Other sales 1,885 1,743
Water conveyance revenue 3,255 1,785
Water Conservation Programs 1,023 943
Other operating revenue 3,759 4,759
Total operating revenues before uncollectibles 70,167 65,177 Estimated uncollectibles, net of bad debt recovery (447) (85) Total operating revenues, net of uncollectibles 69,720 65,092 OPERATING EXPENSES:
Operations 36,091 32,616
Maintenance 5,394 5,851
Purchased energy 5,583 5,748
Water Conservation Programs 360 750
Depreciation 16,010 15,450
Total operating expenses 63,438 60,415
Operating income 6,282 4,677
NON-OPERATING REVENUES (EXPENSES):
Investment income 2,073 2,044
Interest expense and fiscal charges (9,857) (10,412)
Gain on sale of assets 69 155
Other 2,756 2,888
Total non-operating revenues (expenses) (4,959) (5,325) Income before capital contributions and transfers 1,323 (648) Capital contributions 3,129 3,119
Transfers out - contributions to the City's general fund (6,518) (6,584) Total capital contributions and transfers (3,389) (3,465) Decrease in net position (2,066) (4,113)
NET POSITION, BEGINNING OF YEAR 302,701 305,078
RESTATEMENT OF NET POSITION (Note 11) - 1,736 NET POSITION, BEGINNING OF YEAR, AS RESTATED 302,701 306,814 NET POSITION, END OF YEAR 300,635$ 302,701$
See accompanying notes to the financial statements
(in thousands)
For the Fiscal Year
Ended June 30
FINANCIAL STATEMENTS: WATER
City of Riverside Water Utility
STATEMENTS OF CASH FLOWS
2021 2020
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from customers and users 78,233$ 68,456$ Cash paid to suppliers and employees (45,397) (45,674) Other receipts 1,138 974
Net cash provided by operating activities 33,974 23,756 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:
Transfers out - contributions to the City's general fund (6,972) (6,518) Payment on pension obligation bonds (672) (619) Pension obligation bond issuance costs - (76) Proceeds from pension obligation bond, used to pay into employee pension plan - 20,566 Cash paid to employee pension plan from proceeds of pension obligation bond - (20,490) Cash received (paid) on advances from (to) other funds of the City - 139 Net cash used for non-capital financing activities (7,644) (6,998) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:
Purchase of utility plant (16,509) (19,061) Proceeds from the sale of utility plant 132 68 Principal paid on long-term obligations (6,557) (5,737) Interest paid on long-term obligations (9,844) (10,955) Capital contributions 3,062 2,530
Net cash used provided (used) by capital and related financing activities (29,716) (33,155) CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from investment securities - 268 Income from investments 28 2,097
Net cash provided by investing activities 28 2,365 Net decrease in cash and cash equivalents (3,358) (14,032) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $38,909 and $49,881 at June 30, 2020 and June 30, 2019 respectively, reported in restricted accounts) 76,887 90,919 CASH AND CASH EQUIVALENTS, END OF YEAR (including $30,582 and $38,909 at June 30, 2021 and June 30, 2020 respectively, reported in restricted accounts) 73,529$ 76,887$
RECONCILIATION OF OPERATING INCOME
TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Operating income 18,245$ 6,282$
Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation 16,346 16,010
Increase (decrease) in allowance for uncollectible accounts (45) 389 (Increase) in accounts receivable (4,384) (1,780) (Increase) decrease in prepaid expenses (13) 2 Increase in accounts payable and other accruals 869 240 Increase in compensated absences 430 262 Increase in unearned revenue 2,305 3
Increase in Water Conservation Programs payable 18 6 Increase in customer deposits 100 124 Changes in net pension liability and related deferred outflows and inflows of resources (1,108) 1,047 Changes in other postemployment benefits liability and related deferred outflows and inflows of resources 73 197 Other receipts 1,138 974
Net cash provided by operating activities 33,974$ 23,756$ SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:
Capital contributions - capital assets - 599 Reduction of note payable including interest, offset by rent credit 1,864 1,782 See accompanying notes to the financial statements
Ended June 30,
For the Fiscal Year Ended
(in thousands)
SS TT AA TT EEMM EE NNTT SS OO FF CCAA SS HH FF LL OOWW SS 2020 2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Cash received from customers and users 68,456$ 65,239$ Cash paid to suppliers and employees (45,674) (46,190) Other receipts 974 1,132
Net cash provided by operating activities 23,756 20,181 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES:
Transfers out - contributions to the City's general fund (6,518) (6,584) Payment on pension obligation bonds (619) (728) Pension obligation bond issuance costs (76) - Proceeds from pension obligation bond, used to pay into employee pension plan 20,566 - Cash paid to employee pension plan from proceeds of pension obligation bond (20,490) - Cash received (paid) on advances from (to) other funds of the City 139 (8) Net cash used for non-capital financing activities (6,998) (7,320) CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES:
Purchase of utility plant (19,061) (21,670) Proceeds from the sale of utility plant 68 183 Principal paid on long-term obligations (5,737) (5,841) Interest paid on long-term obligations (10,955) (9,442) Proceeds from revenue bonds, including premium - 53,566 Revenue bond refunding cost - (760) Bond issuance costs - (526)
Capital contributions 2,530 2,489
Net cash used provided (used) by capital and related financing activities (33,155) 17,999 CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from investment securities 268 (268) Income from investments 2,097 2,097
Net cash provided by investing activities 2,365 1,829 Net increase (decrease) in cash and cash equivalents (14,032) 32,689 CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR (including $49,881 and $10,766 at June 30, 2019 and June 30, 2018 respectively, reported in restricted accounts) 90,919 58,230 CASH AND CASH EQUIVALENTS, END OF YEAR (including $38,909 and $49,881 at June 30, 2020 and June 30, 2019 respectively, reported in restricted accounts) 76,887$ 90,919$
RECONCILIATION OF OPERATING INCOME
TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Operating income 6,282$ 4,677$
Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation 16,010 15,450
Increase (decrease) in allowance for uncollectible accounts 389 (24) (Increase) decrease in accounts receivable (1,780) 223 Decrease in prepaid expenses 2 11
Increase (decrease) in accounts payable and other accruals 240 (984) Increase in compensated absences 262 177 Increase (decrease) in unearned revenue 3 (25) Increase (decrease) in Water Conservation Programs payable 6 (67) Increase (decrease) Increase in customer deposits 124 (24) Changes in net pension liability and related deferred outflows and inflows of resources 1,047 (480) Changes in other postemployment benefits liability and related deferred outflows and inflows of resources 197 118 Other receipts 974 1,129
Net cash provided by operating activities 23,756$ 20,181$ SCHEDULE OF NON-CASH INVESTING, CAPITAL AND FINANCING ACTIVITIES:
Capital contributions - capital assets 599 630 Reduction of note payable including interest, offset by rent credit 1,782 1,756 Principal balance of revenue bonds refunded - 68,800 See accompanying notes to the financial statements
Ended June 30,
For the Fiscal Year Ended
(in thousands)
FINANCIAL STATEMENTS: WATER
99 NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS 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
In June 2017, the GASB issued Statement No. 87, Leases. The objective of this Statement is to better meet the information needs of financial statement users by improving accounting and financial reporting for leases. The Statement requires recognition of certain lease assets and liabilities for leases that previously were classified as operating leases. The requirements of this Statement are effective for reporting periods beginning after June 15, 2021. The Department is evaluating the impact of this standard.
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 $3,743 at June 30, 2021, and $3,378 at June 30, 2020.
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.
WWAATTEERR UUTTIILLIITTYY::
NNOOTTEESS TTOO TTHHEE FFIINNAANNCCIIAALL SSTTAATTEEMMEENNTTSS NOTES TO THE FINANCIAL STATEMENTS: WATER
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 lease purchase financing 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 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 NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS (( CCOO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
101
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, 2021, 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, 2021 and 2020 were as follows: Property Reserve $5,203 and $5,151, Recycled Water Reserve $1,151 and $1,140, Customer Deposits $770 and $703, and Capital Repair and Replacement Reserve $2,340 and $2,317, respectively. The combined total for these reserves was $9,464 and $9,311 at June 30, 2021 and 2020, 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 PREMIUM/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, 2021 and 2020 was $1,013 and $913, respectively.
NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS (( CCOO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
COMPENSATED ABSENCES
The accompanying financial statements include accruals for salaries, fringe benefits and compensated absences due to employees at June 30, 2021 and 2020. 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 $2,719 at June 30, 2021, and $2,289 at June 30, 2020.
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.
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 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, 2021, 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, 2021 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 $417 and $460 for the years ended June 30, 2021 and 2020, respectively. Any losses above the City’s reserves would be covered through increased rates charged to the Water 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 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 NN OO TT EE 11.. SSUU MM MM AA RR YY OOFF SSIIGG NN II FF II CCAANN TT AA CC CCOO UU NN TT II NNGG PP OO LLII CC IIEESS (( CCOO NN TT IINN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
103
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.
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 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. 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 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, 2021 and 2020, $6,972 and $6,518, respectively was transferred representing 11.5 percent.
NN OO TT EE 11 .. SSUU MM MMAA RRYY OO FF SSII GG NNIIFF II CCAANN TT AA CC CCOOUU NN TT IINN GG PP OO LLII CCII EESS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
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.
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 normally adopts the Water Utility’s budget in June biennially via resolution, however due to the impact of COVID-19, the City adopted an emergency fiscal year 20/21 budget.
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.
NN OO TT EE 11 .. SSUU MM MMAA RRYY OO FF SSII GG NNIIFF II CCAANN TT AA CC CCOOUU NN TT IINN GG PP OO LLII CCII EESS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
105
NN OO TT EE 22.. CCAA SSHH AANN DD IINN VV EE SSTT MM EE NNTT SS Cash and investments at June 30, 2021 and 2020, consist of the following (in thousands):
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.
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, 2021 and 2020:
June 30, 2021 June 30, 2020
Equity interest in City Treasurer's investment pool 53,421$ 48,061$ Cash and cash equivalents at fiscal agent 20,108 28,826 Total cash and investments 73,529$ 76,887$
The amounts above are reflected in the accompanying financial statements as:
June 30, 2021 June 30, 2020
Unrestricted cash and cash equivalents 42,947$ 37,978$ Restricted cash and cash equivalents 10,474 10,083 Restricted cash and cash equivalents at fiscal agent 20,108 28,826 Total cash and investments 73,529$ 76,887$
Fair Value
Investment Type
June 30,
2021
Fair Value
Quoted Prices in
Active Ma rke ts
for Identical
Asse ts (Le ve l 1)
Significant Other
Observable
Inputs (Level 2)
Significant
Unobservable
Inputs (Level 3)
Inve stme nts
not Subject to
Fair Value
Hierarchy
Held by fiscal agent
Money market funds 20,108$ -$ -$ -$ 20,108$ City Treasurer's investment pool 1
Money market funds 513 - - - 513 Joint powers authority pools 8,825 8,825 - - - Local agency investment fund 9,705 - - - 9,705 Mortgage pass-through securities 2,169 - 2,169 - - Asset-backed securities 1,638 - 1,638 - - US Treasury obligations 11,714 - 11,714 - - Federal agency obligations 8,701 - 8,701 - - Medium-term corporate notes 7,695 - 7,695 - - Supranational securities 1,849 - 1,849 - - Negotiable certificate of deposit 612 - 612 - - Total 73,529$ 8,825$ 34,378$ -$ 30,326$ NOTES TO THE FINANCIAL STATEMENTS: WATER
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.
Investment Type
June 30,
2020
Fair Value
Quoted Prices in
Active Ma rke ts
for Identical
Asse ts (Le ve l 1)
Significant Other
Observable
Inputs (Level 2)
Significant
Unobservable
Inputs (Level 3)
Inve stme nts
not Subject to
Fair Value
Hierarchy
Held by fiscal agent
Money market funds 28,826$ -$ -$ -$ 28,826$ City Treasurer's investment pool 1
Money market funds 365 - - - 365 Joint powers authority pools 11,690 11,690 - - - Local agency investment fund 9,709 - - - 9,709 Mortgage pass-through securities 2,125 - 2,125 - - Asset-backed securities 331 - 331 - - US Treasury obligations 13,350 - 13,350 - - Federal agency obligations 5,538 - 5,538 - - Medium-term corporate notes 4,415 - 4,415 - - Supranational securities 279 - 279 - - Negotiable certificate of deposit 259 - 259 - - Total 76,887$ 11,690$ 26,297$ -$ 38,900$ NN OO TT EE 22.. CC AA SSHH AA NN DD IINN VVEE SSTT MM EE NNTT SS (( CCOO NN TT II NNUU EE DD)) NOTES TO THE FINANCIAL STATEMENTS: WATER
107
Cash and investments distribution by maturities as of June 30, 2021 and 2020, are as follows:
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.
June 30, 2021 12 Months 13 to 36 37 to 60
Investment Type Fair Value or less Months Months
Held by fiscal agent
Money market funds 20,108$ 20,108$ -$ -$ City Treasurer's investment pool 1
Money market funds 513 513 - - Joint powers authority pools 8,825 8,825 - - Local agency investment fund 9,705 9,705 - - Mortgage pass-through securities 2,169 721 1,332 116 Asset-backed securities 1,638 - 465 1,173 US Treasury obligations 11,714 1,787 7,490 2,437 Federal agency obligations 8,701 992 3,190 4,519 Medium-term corporate notes 7,695 1,188 1,458 5,049 Supranational securities 1,849 - - 1,849 Negotiable certificate of deposit 612 612 - - Total 73,529$ 44,451$ 13,935$ 15,143$
June 30, 2020 12 Months 13 to 36 37 to 60
Investment Type Fair Value or less Months Months
Held by fiscal agent
Money market funds 28,826$ 28,826$ -$ -$ City Treasurer's investment pool 1
Money market funds 365 365 - - Joint powers authority pools 11,690 11,690 - - Local agency investment fund 9,709 9,709 - - Mortgage pass-through securities 2,125 - 1,448 677 Asset-backed securities 331 - - 331 US Treasury obligations 13,350 2,473 6,209 4,668 Federal agency obligations 5,538 523 2,166 2,849 Medium-term corporate notes 4,415 346 2,593 1,476 Supranational securities 279 - - 279 Negotiable certificate of deposit 259 129 130 - Total 76,887$ 54,061$ 12,546$ 10,280$ Remaining Maturity (In Months)
Remaining Maturity (In Months)
NN OO TT EE 22.. CC AA SSHH AA NN DD IINN VVEE SSTT MM EE NNTT SS (( CCOO NN TT II NNUU EE DD)) NOTES TO THE FINANCIAL STATEMENTS: WATER
Presented below is the actual rating as of June 30, 2021 and 2020 for each investment type:
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.
Investment Type
June 30, 2021
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds 20,108$ -$ - $ 20,108 $ -$ City Treasurer's investment pool 1
Money market funds 513 1 7 9 - - 3 3 4 Joint powers authority pools 8,825 8,825 - - - Local agency investment fund 9,705 - - - 9,705 Mortgage pass-through securities 2,169 2,169 - - - Asset-backed securities 1,638 1,331 - - 3 0 7 US Treasury obligations 11,714 11,714 - - - Federal agency obligations 8,701 8,354 - - 3 4 7 Medium-term corporate notes 7,695 - 2,795 4 , 2 7 4 6 2 6 Supranational securities 1,849 1,247 - - 6 0 2 Negotiable certificate of deposit 612 - - - 6 1 2 Total 73,529$ 33,819 $ 2,795 $ 24,382 $ 12,533 $ Rating as of Year End
Investment Type
June 30, 2020
Fair Value AAA AA A Unrated
Held by fiscal agent
Money market funds 28,826$ -$ - $ 28,826 $ -$ City Treasurer's investment pool 1
Money market funds 365 3 3 - - 3 3 2 Joint powers authority pools 11,690 11,690 - - - Local agency investment fund 9,709 - - - 9,709 Mortgage pass-through securities 2,125 - - - 2,125 Asset-backed securities 331 - - - 3 3 1 US Treasury obligations 13,350 - 13,350 - - Federal agency obligations 5,538 - 5,092 - 4 4 6 Medium-term corporate notes 4,415 - 1,998 2 , 4 1 7 - Supranational securities 279 2 7 9 - - - Negotiable certificate of deposit 259 - - - 259 Total 76,887$ 12,002 $ 20,440 $ 31,243 $ 13,202 $ Rating as of Year End
NN OO TT EE 22.. CCAA SSHH AANN DD IINN VV EE SSTT MM EE NNTT SS (( CCOO NN TT IINN UU EE DD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
109
NN OO TT EE 33.. UU TT II LLII TT YY PP LL AANN TT
The following is a summary of changes in utility plant during the fiscal years ended June 30, 2021 and 2020 (in thousands):
Balance Balance Balance
As of Retirements / As of Retirements/ As of
6/30/2019 Additions Trans fers 6/30/2020 Additions Transfers 6/30/2021 Source of supply 68,886$ 6,885$ (343)$ 75,428$ 2,674$ -$ 78,102$ Pumping 32,817 215 - 33,032 2,130 - 35,162 Treatment 44,614 38 - 44,652 116 - 44,768 Transmission and distribution 522,408 8,951 (361) 530,998 4,746 (224) 535,520 General 16,728 15 - 16,743 - (285) 16,458 Intangible 4,162 9 - 4,171 - - 4,171 Depreciable utility plant 689,615 16,113 (704) 705,024 9,666 (509) 714,181 Less accumulated depreciation
Source of supply (20,452) (1,671) 343 (21,780) (1,898) - (23,678) Pumping (13,604) (702) - (14,306) (710) - (15,016) Treatment (15,092) (1,276) - (16,368) (1,278) - (17,646) Transmission and distribution (181,205) (11,136) 361 (191,980) (11,282) 209 (203,053) General (12,787) (470) - (13,257) (454) 285 (13,426) Intangible (2,198) (755) - (2,953) (724) - (3,677) Accumulated depreciation (245,338) (16,010) 704 (260,644) (16,346) 494 (276,496) Net depreciable utility plant 444,277 103 - 444,380 (6,680) (15) 437,685 Land 20,841 - - 20,841 - - 20,841 Intangible, non-amortizable 10,841 82 - 10,923 52 - 10,975 Construction in progress 19,392 19,464 (15,515) 23,341 16,459 (9,665) 30,135 Nondepreciable utility plant 51,074 19,546 (15,515) 55,105 16,511 (9,665) 61,951 Total utility plant 495,351$ 19,649$ (15,515)$ 499,485$ 9,831$ (9,680)$ 499,636$ NOTES TO THE FINANCIAL STATEMENTS: WATER
NN OO TT EE 44.. LLOO NN GG -- TTEE RR MM OOBB LLII GGAA TTII OO NN SS The following is a summary of changes in long-term obligations during the fiscal years ended June 30, 2021 and 2020 (in thousands):
Long-term debt consists of the following (in thousands):
CONTRACTS PAYABLE
PENSION OBLIGATION BONDS PAYABLE
Balance Balance Balance Due
As of As of As of Within
6/30/2019 Additions Reductions 6/30/2020 Additions Reductions 6/30/2021 One Year Revenue bonds 231,639 $ - $ (6,760) $ 224,879 $ - $ (7,573) $ 217,306 $ 6 , 6 4 0$ Pension obligation bonds 3,028 20,626 (619) 23,035 - (672) 22,363 1 , 0 7 5 Direct Borrowings:
Leased purchases 1 , 8 8 4 - ( 2 1 8 ) 1,666 - ( 2 2 1 ) 1 , 4 4 5 2 2 7 Note payable 20,323 483 (1,282) 19,524 - (1,386) 18,138 1 , 4 9 9 Contracts payable - Water
stock acquisition rights 9 3 7 8 2 - 1,019 5 2 (4) 1,067 1 5 0 Total long-term obligations 257,811 $ 21,191 $ (8,879) $ 270,123 $ 52 $ (9,856) $ 260,319 $ 9 , 5 9 1$ June 30, 2021 June 30, 2020
Water Stock Acquisitions: Payable to various water companies 1,067$ 1,019$ Total contracts payable 1,067 1,019
2,141$ 2,469$
20,222 20,566
Total pension obligation bonds payable 22,363 23,035 $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. $201,080 2020 Taxable Pension Obligation Bonds Series A (Misce lla ne ous):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.
NOTES TO THE FINANCIAL STATEMENTS: WATER
111
REVENUE BONDS PAYABLE
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 Wate r Utility’s proportional share of the outstanding principal amount of the bonds was $22,363 and $23,035 as of June 30, 2021 and 2020, 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, 2021.
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 pl ans. It is estimated the issuance w ill save the City’s General Fund $7.6M in pension costs in FY 2022 with a projected overall savings of $178.5 million through the life of the bonds. The fixed rate bonds issued by the City due in annual installments from $1,285 to $14,625 through June 2045, with coupons from 1.6 to 3.9 percent. The Water Utility's proportional share of the miscellaneous plan is 10.2 percent.
June 30, 2021 June 30, 2020
-$ 2,360$
67,790 67,790
24,050 24,050
106,990 110,965
Total water revenue bonds payable 198,830 205,165 Total water revenue bonds, pension obligation bonds and contracts payable 222,260 229,219 Unamortized bond premium 18,476 19,714
Total water revenue bonds, pension obligation bonds and contracts payable, including bond premium 240,736 248,933 Less current portion (7,865) (7,157)
Total long-term water revenue bonds, pension obligation bonds and contracts payable 232,871$ 241,776$
$31,895 2009 Water Refunding/Revenue Series A Bonds: fixed rate bonds due in annual principal installments from $2,270 to $2,360 through October 1, 2020, interest from 4.0 to 5.0 percent
$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
$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
$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 weekly repricing (net interest rate, including swaps, at June 30, 2021 was 3.2 percent). Partially refunded $26,900 on April 1, 2019 with 2019A Water Refunding Bonds.
NNOOTT EE 44 .. LLOO NNGG --TT EE RR MM OO BB LLII GG AA TT II OO NNSS (( CCOO NNTT II NNUUEE DD)) NOTES TO THE FINANCIAL STATEMENTS: WATER
Remaining pension obligation bond debt service payments will be made from revenues of the Water Fund.
Annual debt service requirements to maturity as of June 30, 2021 are as follows (in thousands):
All water revenue bonds are covenanted per the Amended and Restated Resolution No. 17664 (Water) Master Resolution that upon the occurrence and continuation of an event of default, the owners of 25% in aggregate amount of Bond Obligation may, by written notice to the City, declare the entire unpaid principal and accreted value of the bonds due and payable should the City fail to pay its debts as they become due or upon the entry of any decree or order of bankruptcy of the City.
Remaining revenue bond debt service payments will be made from revenues of the Water Fund. Annual debt service requirements to maturity as of June 30, 2021 are as follows (in thousands):
The Water Utility has a number of debt issuances (revenue bonds) outstanding that are collateralized by the pledging of water revenues. The amount and term of the remainder of these commitments are indicated in the revenue bonds payable and annual debt service requirements to maturity tables presented within this Note 4. The purpose of the debt issuances was for the financing of various Water Utility capital improvement projects. For June 30, 2021 and 2020, debt service payments as a percentage of the pledged gross revenue, net of certain expenses where so required by the debt agreement, are indicated in the table below.
Fiscal Year Principal Interest Total
2022 1,075$ 692$ 1,767 $
2023 1,363 670 2 , 0 3 3
2024 1,640 642 2 , 2 8 2
2025 1,815 605 2 , 4 2 0
2026 1,867 562 2 , 4 2 9
2027-2031 5,326 2,200 7 , 5 2 6
2032-2036 4,956 1,414 6 , 3 7 0
2037-2041 3,916 501 4 , 4 1 7
2042-2046 405 20 4 2 5
Total 22,363$ 7,306 $ 29,669 $
Fiscal Year Principal Interest Total
2022 6,640$ 8,793$ 15,433 $
2023 6,915 8,491 15,406
2024 7,215 8,167 15,382
2025 7,540 7,823 15,363
2026 7,875 7,463 15,338
2027-2031 44,900 31,365 76,265
2032-2036 53,675 20,917 74,592
2037-2041 46,400 8,598 54,998
2042-2046 10,225 3,189 13,414
2047-2051 7,445 571 8 , 0 1 6
Premium 18,476 - 18,476
Total 217,306$ 105,377$ 322,683 $
NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
113
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.
LINE OF CREDIT
On February 1, 2019, the City entered into a subordinate line of credit agreement with U.S. Bank, National Association. 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, 2021.
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.
A summary of the derivative activity for the year ended June 30, 2021 is as follows:
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 $3,950 until the debt is completely retired in fiscal year 2036.
Fiscal Year Ended
Description of
Pledged Revenues
Annual Amount of
Pledged Revenue
(net of expens es ) 1, 2
Annual Debt
Service
Payments
Debt Service
Coverage Ratio
June 30, 2021 Water revenues 37,614$ 16,692$ 2.25 June 30, 2020 Water revenues 28,518$ 15,810$ 1.80 1 Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of ($1,107) and $1,046 for June 30, 2021 and 2020, respectively.
2 Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non- cash adjustments of $73 and $197 for June 30, 2021 and 2020, respectively.
Fair Value Change in
Notional as of Fair Value
Amount 6/30/2021 for Fiscal Year
2011 Water Refunding/Revenue Bonds Series A 24,050$ (5,683)$ 2,091$ NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
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, 2021, rates were as follows:
Fair value : As of June 30, 2021, in connection with the swap agreement, the transactions had a total negative fair value of ($5,683). 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, 2021, 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, 2021, 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.
Swap payments and associated debt: As of June 30, 2021, 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.
Interest rate swap: Terms Rates
Fixed payment to counterparty Fixed 3.20000%
Variable payment from counterparty 62.68 LIBOR + 12bps (0.57363%) Net interest rate swap payments 2.62637%
Variable-rate bond coupon payments 0.55643%
Synthetic interest on bonds 3.18280%
NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
115
NOTE PAYABLE
Note payable consists of several agreements with Hillwood Enterprises, L.P. 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 $18,138, as of June 30, 2021.
Estimated annual rent credits, which are adjusted annually based on Consumer Price Index (CPI), to be applied to the land purchase and well relocation agreements commencing in 2014 with an effective interest rate of 3.15 percent, are as follows (in thousands):
Estimated annual rent credits, which are adjusted annually based on CPI, to be applied to the well relocation agreement commencing in 2018 with an effective interest rate of 3.00 percent, are as follows (in thousands):
Fiscal Year
Ending Interes t Rate
June 30, Principal Interes t Swaps , Net Total
2022 -$ 138$ 651$ 789$ 2023 - 138 651 789 2024 - 138 651 789 2025 - 138 651 789 2026 - 138 651 789 2027-2031 6,675 642 3,033 10,350 2032-2036 17,375 238 1,121 18,734 Total 24,050$ 1,570$ 7,409$ 33,029$ Variable-Rate Bonds
Fis cal Year Principal Interes t Total
2022 926$ 267$ 1,193$ 2023 994 242 1,236 2024 1,065 216 1,281 2025 1,139 188 1,327 2026 1,217 158 1,375 2027-2030 5,456 285 5,741 Total 10,797$ 1,356$ 12,153$ Fiscal Year Principal Interes t Total
2022 273$ 116$ 389$ 2023 282 107 389 2024 290 98 388 2025 300 89 389 2026 309 79 388 2027-2031 1,700 243 1,943 2032-2033 662 19 681 Total 3,816$ 751$ 4,567$ NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
Annual rent credits to be applied for the lease termination agreement commencing in 2018, are as follows (in thousands):
LEASE PURCHASE FINANCING
In fiscal year ended June 30, 2017, the Water Utility participated in the City’s lease purchase financing program for the acquisition of water system heavy vehicles and equipment. The heavy vehicles and equipment lease financing is 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 accounts payable and other accruals as of June 30, 2021 and 2020 was $1,445 and $1,666, respectively.
The annual lease payments for the life of the lease are $260 annually through fiscal year ending June 30, 2027. As of June 30, 2021 total outstanding lease payments are $1,558, with $1,445 representing principal and $113 representing interest.
NN OO TT EE 55.. CCOO MMPP EENN SS AA TT EE DD AA BB SSEE NN CCEESS A liability is recorded for unused vacation and similar compensatory leave balances since the employees’ entitlement to these balances are attributable to services already rendered and it is probably that virtually all of these balances will be liquidated by either paid time-off or payments upon termination or retirement.
Below is a summary of changes in Compensated absences for the Water Utility during the fiscal year.
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RREE TT II RREE MM EENN TT PP LLAA NN
PLAN DESCRIPTION
The City contributes to CalPERS, an agent multiple employer public employee defined benefit pension plan.
CalPERS provides retirement and disability benefits, annual cost-of-living adjustments, and death benefits to plan members and beneficiaries. CalPERS acts as a common investment and administrative agent for participating public entities within the State of California. CalPERS issues a publicly available financial report that includes financial statements and required supplementary information for the cost sharing plans that are administered by CalPERS. Benefit provisions and all other requirements are established by state statute and City ordinance. A copy of CalPERS’ annual financial report may be obtained online at Fiscal Year Principal Interes t Total
2022 300$ -$ 300$ 2023 300 - 300 2024 300 - 300 2025 300 - 300 2026 300 - 300 2027-2031 1,500 - 1,500 2032-2033 525 - 525 Total 3,525$ -$ 3,525$ Balance Balance Balance Due
As of As of As of Within
6/30/2019 Additions Reductions 6/30/2020 Additions Reductions 6/30/2021 One Year Compensated absences 2,027$ 1,802$ (1,540)$ 2,289$ 1,776$ (1,346)$ 2,719$ 1,599$ NN OO TT EE 44.. LLOO NNGG -- TT EERR MM OOBB LLII GGAA TT II OONN SS (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
117
www.calpersca.gov. The Water Utility, including Water Conservation Programs, 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 percent 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.
2 nd 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.
3 rd 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.
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
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, 2020 and 2019, the following employees, City-wide, were covered by the benefit terms of the Plan:
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, 2021, the net pension liability of the Plan is measured as of June 30, 2020, using an annual actuarial valuation as of June 30, 2019 rolled forward to June 30, 2020 using standard update procedures. For fiscal year ended June 30, 2020, the net pension liability of the Plan is measured as of June 30, 2019, using an annual actuarial valuation as of June 30, 2018 rolled forward to June 30, 2019 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, 2020 and 2019 actuarial valuations were determined using the following actuarial assumptions:
June 30, 2020 June 30, 2019
Inactive employees or beneficiaries
currently receiving benefits 2,301 2,252
Inactive employees entitled to but
not yet receiving benefits 1,427 1,411
Active employees 1,559 1,606
Meas urement Date
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
119
CHANGES IN ASSUMPTIONS
There was no changes in assumptions in for the measurement date of June 30, 2020.
DISCOUNT RATE
The discount rate used to measure the Plan’s total pension liability was 7.15 percent for measurement date as of June 30, 2020 and 2019. 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.
LONG-TERM DISCOUNT 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 as well as the expected pension fund cash flows. Using historical returns of all of the funds’ asset classes, expected compound (geometric) returns were calculated over the short- term (first 10 years) and the long-term (11+ years) using a building-block approach. Using the expected nominal returns for both short-term and long-term, the present value of benefits was calculated for each fund. The expected rate of return was set by calculating the rounded single equivalent expected return that arrived at the same present value of benefits for cash flows as the one calculated using both short-term Mis cellaneous - Current Year Miscellaneous - Prior Year Valuation Date June 30, 2019 June 30, 2018
Measurement Date June 30, 2020 June 30, 2019
Actuarial Cost Method Entry-Age Normal Cost Method Entry-Age Normal Cost Method Actuarial Assumptions
Discount Rate 7.15% 7.15%
Inflation 2.50% 2.50%
Salary Increase Varies by entry age and service Varies by entry age and service Mortality Rate Table1
Post Retirement Benefit
Increase
The lesser of contract COLA or
2.50% until Purchasing Power
Protection Allowance floor on
purchasing power applies, 2.50%
thereafter
The lesser of contract COLA or
2.50% until Purchasing Power
Protection Allowance floor on
purchasing power applies, 2.50%
thereafter
Derived using CalPERS’ membership data for all funds.
1 The mortality table used w as developed based on CalPERS-specific data. The probabilities of mortality are based on the 2017 CalPERS Experience Study for the period from 1997 to 2015. Pre-retirement and Post-retirement mortality rates include 15 years of projected mortality improvement using 90% of Scale MP-2016 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 December 2017 that can be found on the CalPERS w ebsite.
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
and long-term returns. The expected rate of return was then set equal to the single equivalent rate calculated above and adjusted to account for assumed administrative expenses. The expected real rates of return by asset class are as follows:
CHANGES IN THE NET PENSION LIABILITY
The changes in the Water Utility’s, including Water Conservation Programs, proportionate share of the net pension liability as of June 30, 2021 (measurement date June 30, 2020) and 2020 (measurement date June 30, 2019) for the Plan are as follows:
Current Target Real Return Real Return
Asse t Cla ss (1) Allocation Years 1 - 10 (2) Years 11+ (3) Global Equity 50.00% 4.80% 5.98%
Fixed Income 28.00% 1.00% 2.62%
Inflation Assets 0.00% 0.77% 1.81%
Private Equity 8.00% 6.30% 7.23%
Real Assets 13.00% 3.75% 4.93%
Liquidity 1.00% 0.00% -0.92%
(2) An expected inflation of 2.00% used for this period. (3) An expected inflation of 2.92% used for this period.
June 30, 2020 Measurement Date
(1) In the System's CAFR, 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.
Current Target Real Return Real Return
Asse t Cla ss (1) Allocation Years 1 - 10 (2) Years 11+ (3) Global Equity 50.00% 4.80% 5.98%
Fixed Income 28.00% 1.00% 2.62%
Inflation Assets 0.00% 0.77% 1.81%
Private Equity 8.00% 6.30% 7.23%
Real Assets 13.00% 3.75% 4.93%
Liquidity 1.00% 0.00% -0.92%
(2) An expected inflation of 2.00% used for this period. (3) An expected inflation of 2.92% used for this period.
June 30, 2019 Measurement Date
(1) In the System's CAFR, 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.
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
121
SENSITIVITY OF THE NET PENSION LIABILITY TO CHANGES IN THE
DISCOUNT RATE
The following presents the Water Utility’s, including Water Conservation Programs, proportionate share of the net pension liability of the Plan, calculated using the discount rate of 7.15 percent, 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:
Detailed information about the Plan’s fiduciary net position is available in the separately issued CalPERS financial reports.
PENSION EXPENSES AND DEFERRED OUTFLOWS/INFLOWS OF RESOURCES
RELATED TO PENSION
For the fiscal years ended June 30, 2021 and 2020, the Water Utility, including Water Conservation Programs, recognized pension expense of $1,563 and $5,016, respectively. At June 30, 2021 and 2020, the Water Utility, including Water Conservation Programs, reported deferred outflows of resources and deferred inflows of resources related to pension from the following sources:
Net Pension Proportion of
June 30, 2021 Liability the Plan
Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 12,203$ 10.16% Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 31,840 10.90% Changes - Increase / (Decrease) (19,637) -0.74% June 30, 2020
Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 31,840$ 10.90% Proportion - Reporting date June 30, 2019 (Measurement Date June 30, 2018) 30,737 11.03% Changes - Increase / (Decrease) 1,103 -0.13% Discount Rate
- 1%
(6. 15%)
Current
Discount Rate
(7. 15%)
Discount Rate
+1%
(8. 15%)
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 laibility
$ 32,609 $ 12,203 $ (4,593) $ 52,946 $ 31,840 $ 14,479 Meas urement Date
June 30, 2020
Meas urement Date
June 30, 2019
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
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, 2021.
Amounts reported as deferred outflows of resources and deferred inflows of resources related to pensions will be recognized as pension expense as follows:
NN OO TT EE 77.. OO TT HH EE RR PPOO SS TT-- EEMM PP LL OO YY MM EENN TT BB EENN EEFF II TT SS (( OO PP EEBB ))
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 benefit to eligible retirees and beneficiaries. Retiree and spousal coverage terminates when the Deferred
Outflows of
Re source s
Deferred
Inflows of
Re source s
Deferred
Outflows of
Re source s
Deferred
Inflows of
Re source s
Pension contributions subsequent to
measurement date $ 2,671 -$ $ 24,459 -$ Change in assumptions - (350) 1,581 (1,723) Differences between expected and actual
experience 718 (183) 579 (1,403) Net difference between projected and actual
earnings on pension plan investments 1,532 - - (576) Total 4,921$ (533)$ 26,619$ (3,702)$ June 30, 2021 June 30, 2020
Year Ended
June 30
Deferred Outflows/
(Inflows) of
Res ources
2022 (430)$
2023 721
2024 802
2025 624
2026 -
Therafter -
Total 1,717$
NN OO TT EE 66.. EEMM PP LLOO YY EE EE RR EETT II RREE MM EENN TT PP LLAA NN (( CCOO NN TT II NNUU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
123
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, 2020, the following employees, City-wide, were covered by the benefit terms:
ACTUARIAL ASSUMPTIONS
The total OPEB liability was determined by actuarial valuation as of June 30, 2020 and 2019, using the following actuarial assumptions:
Meas urement Date Meas urement Date
June 30, 2020 June 30, 2019
Inactive plan members or beneficiaries
currently receiving benefits
274 274
Inactive plan members entitled to but
not yet receiving benefits
- -
Active plan members 2,138 2,138
NN OO TT EE 77 -- OO TT HH EE RR PP OO SSTT -- EE MM PP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
CHANGES OF ASSUMPTIONS
In 2020, the discount rate was changed from 3.51 percent to 2.66 percent.
SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN HEALTHCARE COST
TREND RATES
The following presents the Water Utility’s, including Water Conservation Programs, proportionate share of the City’s total OPEB liability, calculating using the healthcare trend rate of 6.25% and 6.50% for measurement date as of June 30, 2020 and June 30, 2019 respectively, 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:
Valuation Date
Measurement Date
Actuarial Cost Method
Actuarial Assumptions
Discount rate
Inflation rate
Payroll Increases:
Merit Increases:
Mortality
Heathcare Trend Rates Fiscal Year
End Future Year Trend
Fiscal Year
End Future Year Trend
2020 - 2020 6.50%
2021 6.25% 2021 6.25%
2022 6.00% 2022 6.00%
2023 5.75% 2023 5.75%
2024 5.50% 2024 5.50%
2025 5.25% 2025 5.25%
2026 5.00% 2026 5.00%
2027 4.75% 2027 4.75%
2028 + 4.50% 2028 + 4.50%
3% per annum
3.0%, plus merit increases based on the
CalPERS experience study as of December
2017
Merit increases from the CalPERS pension
plan experience study as of December 2017.
The benefits are not payroll related but each
individual’s projected cost is allocated over
their lifetime as a level-percentage of pay.
SOA Pub-2010 General Total Dataset
Headcount Weighted Mortality Table fully
generational using Scale MP-2019
3% per annum
3.0%, plus merit increases based on the
CalPERS experience study as of December
2017
Merit increases from the CalPERS pension
plan experience study as of December 2017.
The benefits are not payroll related but each
individual’s projected cost is allocated over
their lifetime as a level-percentage of pay.
SOA Pub-2010 General Total Dataset
Headcount Weighted Mortality Table fully
generational using Scale MP-2019
Mis cellaneous - Prior Year
June 30, 2018
June 30, 2019
Pay-as-you-go for
3.51% per annum. This discount rate is the
maximum of the range of 3-20 year municipal
bond rate indices: S&P Municipal Bond 20
Year High Grade Rate Index, Bond Buyer 20-
Bond GO index, Fidelity GO AA 20 Year Bond
Mis cellaneous - Current Year
Pay-as-you-go for
3.51% as of July 1, 2019 and 2.66% as of
June 30, 2020 for accounting disclosure
purposes. Refer to the
Discussion of Discount Rates section for more
information on selection of the discount rate.
June 30, 2019
June 30, 2020
NN OO TT EE 77 -- OO TT HH EE RR PP OO SSTT -- EE MM PP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
125
SENSITIVITY OF TOTAL OPEB LIABILITY TO CHANGES IN DISCOUNT RATES The following presents the Water Utility’s, including Water Conservation Programs, proportionate share of the City’s total OPEB liability, calculating using the discount rate of 2.66% and 3.51% for measurement date as of June 30, 2020 and 2019 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:
CHANGE IN TOTAL OPEB LIABILITY
For fiscal year ended June 30, 2021 and 2020, the Water Utility’s, including Water Conservation Programs, recognized total OPEB expense of $73 and $197 respectively. The following table shows the change in the Water Utility’s, including Water Conservation Programs, proportionate share of the City’s total OPEB liability for the year ended June 30, 2021 (measurement date June 30, 2020) and the year ended June 30, 2020 (measurement date June 30, 2019):
DEFERRED OUTFLOWS/INFLOWS OF RESOURCES RELATED TO OPEB
At June 30, 2021, the Water Utility, including Water Conservation Programs, reported deferred inflows of resources related to OPEB from the following sources:
1% Decrease
Current
healthcare cost
trend rate 1% Increas e 1% Decreas e
Current
healthcare cost
trend rate 1% Increase
Water Utility's
proportionate share of
total OPEB laibility
$ 3,977 $ 4,550 $ 5,236 $ 3,877 $ 4,382 $ 4,985 Meas urement Date
June 30, 2020
Meas urement Date
June 30, 2019
1% Decrease
(1.66%)
Current Discount
Rate
(2.66%)
1% I ncre a se
(3.66%)
1% Decrease
(2.51%)
Current Discount
Rate
(3.51%)
1% Increase
(4.51%)
Water Utility's
proportionate share of
total OPEB laibility
$ 5,000 $ 4,550 $ 4,144 $ 4,845 $ 4,382 $ 3,972 Meas urement Date
June 30, 2020
Meas urement Date
June 30, 2019
Total OPEB Proportion of
June 30, 2021 Liability the City
Proportion - Reporting date June 30, 2021 (Measurement Date June 30, 2020) 4,550$ 8.70% Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 4,382$ 8.76% Changes - Increase / (Decrease) 168 -0.06% June 30, 2020
Proportion - Reporting date June 30, 2020 (Measurement Date June 30, 2019) 4,382$ 8.76% Proportion - Reporting date June 30, 2019 (Measurement Date June 30, 2018) 3,524 9.19% Changes - Increase / (Decrease) 858 -0.43% NN OO TT EE 77 -- OO TT HH EE RR PP OO SSTT -- EE MM PP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
Amounts reported as deferred inflows of resources related to OPEB will be recognized in OPEB expense as follows:
NN OO TT EE 88.. RREE SS TT RRII CCTT EE DD NN EETT PP OO SSII TT IIOONN 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 percent of the monthly accrued interest to be included in the reserve. Certain issues have no debt service reserve requirements (2009A & B, 2011A and 2019A).
NN OO TT EE 99.. CCOO NNSS TT RRUU CC TTII OO NN CCOO MM MM II TTMM EENN TT SS As of June 30, 2021, the Water Utility had commitments (encumbrances) of approximately $7,526 with respect to unfinished capital projects, of which $5,212 is expected to be funded by bonds, and $2,314 to be funded by unrestricted reserves.
NN OO TT EE 1100 .. LLIITT II GG AA TT II OO NN
The Water Utility is a defendant in various lawsuits arising in the normal course of business. Present lawsuits and other claims against the Water Utility are incidental to the ordinary course of operations of the Water Utility and are largely covered by the City’s self-insurance program. In the opinion of management and the City Attorney, such claims and litigation will not have a materially adverse effect upon the financial position or results of operations of the Water Utility.
Deferred Outflows
of Resources
Deferred Inflows
of Resources
17$ (178)$
Changes of assumptions 692 (53) Contributions subsequent to
measurement date 162 -
Total 871$ (231)$
Difference between expected and
actual expense
Deferred Outflows/
Year Ended (Inflows) of
June 30 Resources
2022 76$
2023 76
2024 76
2025 76
2026 76
Therafter 98
Total 478$
NN OO TT EE 77 -- OO TT HH EE RR PP OO SSTT -- EE MM PP LLOO YYMM EENN TT BB EENN EEFF IITT SS (( OOPP EE BB )) (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
127
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 trail 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.
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.
PONGS ET AL. V. CITY OF RIVERSIDE ET AL. (“PONGS II”)
On January 8, 2021, a lawsuit entitled Pongs et al. v. City of Riverside et al. was filed against the City by two minority shareholders of the Gage Canal Company, alleging that the City had breached certain fiduciary duties and a contract related to the City’s operation of the Gage Canal, an irrigation canal owned by the City and operated by the Gage Canal Company. The plaintiffs are seeking over $9M in damages and that the court compel certain actions by the City. No trial date has been set for this action.
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. No trial date has been set for this action.
CITY OF RIVERSIDE V. 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. 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.
NN OO TT EE 1100 -- LLII TT II GG AA TT IIOO NN (( CC OONN TTII NN UU EEDD )) NOTES TO THE FINANCIAL STATEMENTS: WATER
WWAATTEERR UUTTIILLIITTYY::
KKEEYY HHIISSTTOORRIICCAALL OOPPEERRAATTIINNGG DDAATTAA FISCAL YEAR 2020/21 2019/20 2018/19 2017/18 2016/17
WATER SUPPLY (ACRE FEET)
Potable water production1
72,215 64,827 64,379 69,778 64,407
Percentage pumped2
100.00% 100.00% 100.00% 100.00% 100.00%
System peak day (gallons)3
91,900,000 89,600,000 90,200,000 83,000,000 81,000,000
WATER USE
Number of meters as of year end
Residential 59,782 59,598 59,456 59,601 59,453
Commercial/Industrial4 6,080 6,068 6,028 5,705 5,640
Other4
336 365 319 334 335
Total 66,198 66,031 65,803 65,640 65,428
CCF* sales
Residential 16,149,357 14,610,481 14,157,606 15,564,143 14,219,498 Commercial/Industrial4 10,069,176 9,126,132 9,191,682 9,573,518 8,683,382 Other4
835,300 787,119 805,022 900,596 844,041
Subtotal 27,053,833 24,523,732 24,154,310 26,038,257 23,746,921 Wholesale 1,571,549 1,002,289 1,673,411 1,476,117 1,593,808 Total 28,625,382 25,526,021 25,827,721 27,514,374 25,340,729 *(CCF equals 100 cubic feet)
WATER FACTS
Average annual CCF
per residential customer 270 245 238 261 240 Average price ($/CCF)
per residential customer $2.77 $2.67 $2.50 $2.39 $2.46
Debt service coverage ratio (DSC)5, 6,7
2.25 1 . 8 0 1.68 2.16 2 . 0 4 Employees8
165 165 159 159 174 1 Water pumping figures have been adjusted to include retail and w holesale potable w ater production. 2 No purchased w ater.
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 w ith current Water Rate Plan. 5 Interest expense used to calculate DSC is net of federal subsidy on Build America Bonds. 8 Approved positions.
6 Excludes GASB 68 Accounting and Financial Reporting for Pension non-cash adjustments of ($1,107), $1,046, ($482), $3,149, and ($85), for fiscal years 20/21 through FY16/17, respectively.
7 Excludes GASB 75 Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions non-cash adjustments of $73, $197, $118 and $265, for fiscal years 20/21 through FY 17/18, respectively.
KEY HISTORICAL OPERATING DATA: WATER
129
22 00 22 00 //22 00 22 11 WWAA TT EE RR RREE VV EENN UU EE AA NN DD RREE SSOO UU RR CC EESS
RR EESS IIDD EENN TT II AA LL WWAA TT EE RR RR AATT EE CCOO MMPP AA RRIISS OO NN -- 2211 CCCC FF PP EERR MM OO NN TT HH (( AASS OOFF JJUU NNEE 33 00,, 2200 2211))
SOURCE OF
REVENUE
Residential Sales 53¢
Commercial Sales 28¢
Other Revenue 16¢
Other Sales 3¢
DISTRIBUTION OF
REVENUE
Operations and Maintenance 54¢
Debt Service 20¢
Additions & Replacements to the System 9¢
Transfers to the City'S General Fund* 8¢
Additional Reserves 8¢
Water Conservation 1¢
WATER RESOURCES
San Bernardino Basin Wells 68%
Riverside Basin Wells 32%
Purchased Water 0%
Western MWD
Eastern MWD
Riverside
Public
Utilities
$0
$20
$40
$60
$80
$100
$120
124% Higher 100% Higher $51
*Based on transfer of 11.5% of fiscal year
2019/2020 gross operating revenues,
including adjustments
$114 $102
KEY HISTORICAL OPERATING DATA: WATER
WWAATTEERR KKEEYY OOPPEERRAATTIINNGG IINNDDIICCAATTOORRSS
65,428
65,640
65,803
66,031
66,198
2017
2018
2019
2020
2021
Number of Meters At Year End
$62.6
$66.7
$65.1
$69.7
$80.3
2017
2018
2019
2020
2021
Total Operating Revenue (In Millions)
64,407
69,778
64,379
64,827
72,215
2017
2018
2019
2020
2021
Potable Water Production (In Acre Feet)
81.0 83.0
90.2 89.6
91.9 2017
2018
2019
2020
2021
Peak Day Demand (In Millions of Gallons)
$5.7
$6.2
$6.6
$6.5
$7.0
2017
2018
2019
2020
2021
General Fund Transfer (In Millions)
KEY HISTORICAL OPERATING DATA: WATER
131
WW AA TT EE RR FF AA CC TT SS AA NN DD SS YY SS TT EE MM DD AA TT AA
Established ................................................................................................................ 1913
Service Area Population ....................................................................................... 324,243
Service Area Size (square miles) ............................................................................. 74.24
System Data
Smallest Pipeline .................................................................................................. 2.0” Largest Pipeline .................................................................................................. 72.0” Miles of Pipeline ................................................................................................... 991 Number of Domestic Wells ..................................................................................... 56 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 ................................................................................... 8,012 Daily Average Production (gallons) .......................................................... 66,800,000 2020-2021 Peak Day (gallons) ................................................................ 91,900,000 08/14/20, 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 ............................................................................................ AAA
KEY HISTORICAL OPERATING DATA: WATER
RIVERSIDE PUBLIC UTILITIES
3750 University Avenue
3rd Floor
Riverside, CA 92501
(951) 826-2135
RiversidePublicUtilities.com